CONSOL Energy Inc
ITEM 1.
Business
CONSOL Energy's Business Introduction
CONSOL Energy safely and responsibly produces coal and natural gas for global energy and raw material markets, which include the electric power generation industry and the steelmaking industry. During the year ended December 31, 2011, we produced 62.6 million tons of high-British thermal unit (Btu) bituminous coal from 12 mining complexes in the United States. During this same period, our natural gas production totaled 153.5 net billion cubic feet equivalent (Bcfe) from approximately 15,000 gross natural gas wells primarily in Appalachia.
Additionally, we provide energy services, including river and dock services, terminal services, industrial supply services, water services and land resource management services.
CONSOL Energy's History
CONSOL Energy was incorporated in Delaware in 1991. Our coal operations began in 1864. CONSOL Energy's beginnings as the “Consolidation Coal Company” in Western Maryland led to growth and expansion through all major coal producing regions in the United States. CONSOL Energy entered the natural gas business in the 1980s to increase the safety and efficiency of our coal mines by capturing methane from coal seams prior to mining, which makes the mining process safer and more efficient. Over the past five years, CONSOL Energy's natural gas business has grown by over 164% to produce 153.5 net Bcfe in 2011. This business has grown from coalbed methane production in Virginia into other unconventional production, such as Marcellus Shale, in the Appalachian basin. This growth was accelerated with the 2010 asset acquisition of the Appalachian E&P business of Dominion Resources, Inc. (Dominion Acquisition). Subsequently, in August and September
2011, we announced two strategic joint ventures, one with Noble Energy, Inc. (Noble) and one with a subsidiary of Hess Corporation (Hess). These joint ventures will allow the acceleration of development of the assets acquired in the Dominion Acquisition and will focus on the development of our Marcellus and Utica asset holdings.
CONSOL Energy's Strategy
CONSOL Energy's strategy is to continue to build the Company into a large integrated energy company.
CONSOL Energy defines itself through its core values which are:
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Safety
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Compliance
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Continuous Improvement
These values are the foundation of CONSOL Energy's identity and are the basis for how management defines continued success. We believe CONSOL Energy's rich resource base, coupled with these core values allow CONSOL Energy to create value for the long-term. The electric power industry generates over two-thirds of its output by burning coal or natural gas, the two fuels we produce. We believe that the use of coal and natural gas will continue for many years as the principal fuel sources for electricity in the United States. Additionally, we believe that as worldwide economies grow, the demand for electricity from fossil fuels will grow as well, resulting in expansion of worldwide demand for our coal and natural gas.
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Source: U.S. Energy Information Administration
Although coal is projected to lose a small percentage of market share in the U.S. electric generation market, we believe that our efficient, long-lived, well capitalized longwall mines that operate near major U.S. population centers will continue to maintain their existing market share in the U.S. thermal coal market.
We expect natural gas to become a significant contributor to the domestic electric generation mix as well as industrial segments of the U.S. economy. Also, natural gas may potentially become a significant contributor to the transportation market. Our increasing gas production will allow CONSOL Energy to participate in these markets.
The following charts show CONSOL Energy's recent growth in international coal sales and metallurgical coal sales.
CONSOL Energy's Capital Expenditure Budget
CONSOL Energy's 2012 capital expenditure budget totals $1.5 billion which is an increase from the $1.4 billion invested in 2011. The budget includes $676 million for coal, $623 million for gas, $135 million for water, and $110 million for other. The budget reflects the plan to invest in our highest rate of return projects: the organic opportunities in coal, gas, and liquid hydrocarbons. CONSOL Energy has the ability to adjust these planned investments should circumstances warrant.
The table below categorizes the 2011 actual capital expenditures and the planned 2012 capital expenditure budget.
CONSOL Energy's Operations
The following map provides the location of CONSOL Energy's coal and gas operations by region:
CONSOL Energy Operations Highlights - Coal
We have consistently ranked among the largest coal producers in the United States based upon total revenue, net income and operating cash flow. We produced 62.6 million tons of coal in 2011. Our production of 62.4 million tons of coal in 2010 accounted for approximately 6% of the total tons produced in the United States and almost 14% of the total tons produced east of the Mississippi River during 2010, the latest year for which statistics are available. CONSOL Energy holds approximately 4.5 billion tons of proved and probable coal reserves located in northern Appalachia (62%), the mid-western United States (17%), central Appalachia (15%), the western United States (4%), and in western Canada (2%) at December 31, 2011. We are one of the premier coal producers in the United States by several measures:
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We produce one of the largest amounts of coal east of the Mississippi River;
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We control one of the largest amounts of recoverable coal reserves east of the Mississippi River;
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We control the fourth largest amount of recoverable coal reserves among United States coal producers; and
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We are one of the largest United States producers of coal from underground mines.
The following table ranks the 20 largest underground mines in the United States by tons of coal produced in calendar year 2010, the latest year for which statistics are available.
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Source: National Mining Association, EIA
CONSOL Energy continues to derive a substantial portion of its revenue from sales of coal to electricity generators in the United States. In 2011, sales to domestic electric generators comprised approximately 60% of coal revenue and 48% of total revenue. The largest customer represented approximately 15% of coal revenue and 12% of total revenue. The largest four customers represent approximately 40% of coal revenue and over 30% of total revenue. As natural gas revenue continues to grow, we expect the relative contribution of our largest coal customers to diminish.
CONSOL Energy Operations Highlights - Gas
CONSOL Energy is a leader in developing unconventional gas resources including the development of coalbed methane (CBM) production in the Eastern United States. Our gas operations produced 153.5 net Bcfe made up of a combination of CBM (60%), which is gas that resides in coal seams, natural gas from various shallow oil and gas sites (21%), natural gas from the Marcellus Shale (18%), and other unconventional reservoirs (1%). CONSOL Energy reported estimated net proved gas reserves of 3.5 trillion cubic feet. These reserves were made up of CBM (50%), Marcellus (25%), shallow oil and gas (21%) and other (4%). CONSOL Energy controls considerable resource positions in other unconventional shale plays including: Chattanooga, New Albany, Utica, Huron and other shales.
Our position as a gas producer is highlighted by several measures:
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We are one of the largest natural gas producers in Appalachia with approximately 15,000 total gross wells in Appalachia comprising 8% of all Appalachian wells based on 2009 U.S. Energy Information Administration data, the latest year for which statistics are available.
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We are one of the largest CBM producers, with production equal to approximately 35% of total Appalachian CBM production and 59% of Northern Appalachian production (excluding Alabama) based on 2009 U.S. Energy Information Administration data, the latest year for which statistics are available.
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We operate one of the largest gas gathering networks in Appalachia since we gather essentially all of our own production. We own and operate over 4,000 miles of gathering pipelines.
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We have been a pioneer in the exploration of unconventional gas including coalbed methane, Marcellus, Utica, Chattanooga, Huron and New Albany Shales.
In 2011, CONSOL Energy's sales of CBM gas comprised approximately 62% of gas revenue and 8% of total revenue. Sales of Marcellus gas for the same time period comprised approximately 16% of gas revenue and 2% of total revenue, and sales of shallow oil and gas comprised 21% of gas revenue and 3% of total revenue.
Coal 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 2010 National Mining Association Survey to have produced approximately 58% (based on tonnage produced) of the total United States production in 2010. The U.S. Department of Energy reported 1,285 active coal mines in the United States in 2010, the latest year for which government statistics are available. Demand for our coal by our principal customers is affected by many factors including:
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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 or wind;
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environmental and government regulation;
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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, technological developments, environmental and governmental regulation, 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 markets, both of which are significantly affected by international demand and competition.
Natural Gas Competition
The United States natural gas industry is highly competitive. CONSOL Energy competes with other large producers, thousands of small producers as well as pipeline imports from Canada and Liquefied Natural Gas (LNG) from around the globe. According to data from the Natural Gas Supply Association and the U.S. Department of Energy, the five largest producers of natural gas produced less than 21% of the total U.S. production in the third quarter of 2011. The U.S. Department of Energy reported almost 500,000 producing natural gas wells in the United States in 2009, the latest year for which government statistics are available.
CONSOL Energy's gas operations are 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 competition within our market is based primarily on natural gas commodity trading fundamentals and pipeline transportation availability to the various markets.
Continued demand for CONSOL Energy's natural gas 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 alternative fuel supplies.
Industry Segments
Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2011, 2010 and 2009 is included in Note 25-Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K and incorporated herein.
DETAIL COAL OPERATIONS
Mining Complexes
The following table provides the location of CONSOL Energy's active mining complexes and the coal reserves associated with each
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(1)
The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2011. 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 and Western Allegheny-Knob Creek are both equity affiliates in which CONSOL Energy owns a 49% interest. Reserves reported equal CONSOL Energy's 49% proportionate interest in Harrison Resources' and Western Allegheny-Knob Creek's reserves.
(4)
A portion of these reserves contain metallurgical qualities and are currently being sold on the metallurgical market.
Excluded from the table above are approximately 179.3 million tons of reserves at December 31, 2011 that are assigned to projects that have not produced coal in 2011. These assigned reserves are in the Northern Appalachia (northern West Virginia and Pennsylvania), Central Appalachia (Virginia and eastern Kentucky), the Western U.S. (Utah) and Illinois Basin (Illinois) regions. These reserves are approximately 60% owned and 40% 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 reflect 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, 2011, 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 that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by 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 miles 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 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 the electric power generation industry. Additionally, the growth in worldwide demand for metallurgical coals allows some of our proven and probable coal reserves, currently classified as thermal coals, that possess certain qualities to be sold as metallurgical coal. The addition of this cross-over market adds additional assurance to CONSOL Energy that all of its proven and probable coal reserves are commercially marketable.
The following table sets forth our unassigned proven and probable reserves by region:
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(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, 2011 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.
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 high, 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.
Title to coal properties that we lease or purchase and the boundaries of these properties are verified by law firms retained by us at the time we lease or acquire the properties. 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, 2011, 2010 and 2009.
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.
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 former national 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 this former sulfur dioxide standard may not meet an emission standard for a different pollutant such as mercury, and may not even meet newer sulfur emission standards for all power plants. Clean air regulations that further restrict sulfur dioxide emissions will likely significantly reduce 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, 2011, approximately 0.7 billion tons, or 15%, of our coal reserves met that standard as a compliance coal. It is likely that, within several years, no coal will be "compliant" because federal regulations will require emissions-control technology to be used regardless of the coal's sulfur content. In many cases, our customers have responded to ever-tightening emissions 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, those 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) was required to promulgate 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 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 trillion Btu) 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 more easily captured by scrubbers installed for sulfur control) than sub-bituminous coal, including coals produced in the Powder River Basin. Both high rank and low rank coals are also amenable to other methods of controlling mercury emissions, such as by powder activated carbon injection. The EPA's proposed Clean Air Mercury Rule was vacated by a federal court ruling. The EPA is currently developing new regulations to control multiple hazardous air pollutants, including mercury, from coal-fired plants, the so-called MACT Rule, which is expected to be finalized in 2014. Some states have already adopted a control program for mercury emissions from coal-fired power plants.
Production
In the year ended December 31, 2011, 94% of CONSOL Energy's production came from underground mines and 6% 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, 2011, 91% 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 a low incremental cost.
The following table shows the production, in millions of tons, for CONSOL Energy's mines in the years ended December 31, 2011, 2010 and 2009, the location of each mine, the type of mine, the type of equipment used at each mine, method of transportation and the year each mine was established or acquired by us.
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A
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Auger
S
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Surface
U
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Underground
LW
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Longwall
CM
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Continuous Miner
S/L
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Stripping Shovel and Front End Loaders
R
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Rail
B
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Barge
R/B
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Rail to Barge
T
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Truck
CB
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Conveyor Belt
(1)
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Mine was idled for part of the year(s) presented due to market conditions.
(2)
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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)
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Harrison Resources, Miller Creek Complex, AMVEST-Fola Complex, AMVEST-Terry Eagle Complex, Jones Fork Complex and Western Allegheny-Knob Creek include facilities operated by independent contractors.
(4)
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Production amounts represent CONSOL Energy's 49% ownership interest.
(5)
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Complex was sold in March 2010.
(6)
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Mine 84 was permanently idled in 2011.
Coal Capital Projects
CONSOL Energy anticipates investing $277 million for maintenance-of-production projects and $203 million to projects such as the BMX Mine (see below for BMX description.) Also, $146 million is planned for efficiency improvements such as the overland belt at Enlow Fork Mine and $50 million is planned for health and safety items.
In 2011, capital projects included the continued development of the BMX Mine. This project is expected to add 5 million tons a year of high-quality Pittsburgh seam coal, which will be sold in either the high-volatile metallurgical or thermal markets. An extension of Bailey Mine began in 2009 and production from the first longwall panel is expected to start in early 2014. The total cost of the project is expected to be approximately $662 million of which approximately $132 million was incurred in 2011. As of December 31, 2011, total project-to-date expenditures were approximately $175 million. Included within the scope of this project are certain surface facility upgrades at the Bailey Preparation Plant which are necessary in order for the plant to process the additional coal from the BMX Mine. These upgrades include the construction of several new raw and clean coal silos, expansion of existing railroad facilities, and installation of additional raw coal material handling systems.
In 2011, capital projects included the continued development of the Amonate Complex. This project is expected to add 400 - 600 thousand tons a year of mid-volatile met coal. The total cost of the project is expected to be approximately $53 million of which approximately $22 million was incurred in 2011. Production from the Amonate Complex is expccted to begin in 2012.
Construction of a new slope and overland belt at the Enlow Fork Mine in Pennsylvania began in 2010 and is expected to be completed by the end of 2013. Overland belt projects are expected to enhance safety, improve productivity, increase production and reduce costs. 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 overland belts because older underground belt areas will be sealed. The total cost of the project is expected to be approximately $207 million of which approximately $28 million was incurred in 2011. As of December 31, 2011, total project-to-date expenditures were approximately $38 million.
Also, in accordance with a consent decree with the U.S Environmental Protection Agency and the West Virginia Environmental Protection Agency, CONSOL Energy began construction of an advance water processing system (RO) in Northern West Virginia in 2011. The RO will provide a treatment system for the mine water generated from the Robinson Run, Loveridge, and Blacksville #2 Mines to be in compliance with the existing National Pollution Discharge Elimination System (NPDES) permits. Construction was started in April 2011 and final commissioning of the RO system is expected to be complete by the end of May 2013. Expenditures related to the Northern West Virginia plant of $48.0 million were incurred in 2011 and total costs related to the construction of this plant and related facilities is expected to be approximately $200 million.
Coal Marketing and Sales
Our sales of bituminous coal were at average sales price per ton sold as follows:
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 Charlotte, Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated trading companies.
A breakdown of total coal sales, including our portion of equity affiliates, are as follows:
Approximately 75% of our 2011 coal sales were made to U. S. electric generators,18% of our 2011 coal sales were priced on export markets and 7% of our coal sales were made to other domestic customers. We had approximately 105 customers in 2011. During 2011, one customer individually accounted for more than 10% of total revenue, and the top four coal customers accounted for more than 30% of our total revenues.
Coal Contracts
We sell coal to an established customer base through opportunities as a result of strong business relationships, or through a formalized bidding process. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. The average contract term is between one to three years. However, several multi-year agreements have terms ranging from five to twenty years. As a normal course of business, efforts are made 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. For the year ended December 31, 2011, over 84% of all the coal we produced was sold under contracts with terms of one year or more.
The following table sets forth as of January 26, 2012, CONSOL Energy's estimated production and sales for 2012 through 2014.
Note: N/A means not available or not forecasted. In the thermal sales category, the firm tonnage does not include 4.7 million collared tons in 2013, with a ceiling of $59.78 per ton and a floor of $51.63 per ton or 7.0 million collared tons in 2014, with a ceiling of $60.13 per ton and a floor of $46.76 per ton. Total estimated coal sales for 2012, 2013 and 2014 include 0.4, 0.6 and 0.6 million tons, respectively, from Amonate. The Amonate tons are not included in the category breakdowns. None of the Amonate tons have been sold.
Coal pricing for contracts with terms of one year or less is generally fixed. Coal pricing for multiple-year agreements generally provides the opportunity to periodically adjust the contract prices through pricing mechanisms consisting of one or more of the following:
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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
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Price 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.
The volume of coal to be delivered is specified in each of our coal contracts. Although the volume to be delivered under the coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits.
Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include, but are not limited to, labor disputes and unexpected significant geological conditions. Depending on the language of the contract, some contracts may terminate upon continuance of an event of force majeure that extends for a period greater than three to twelve months.
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, 2011 we operated 22 towboats, 5 harbor boats and a fleet of approximately 625 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.
DETAIL GAS OPERATIONS
Our Gas operations are located throughout Appalachia. While CBM remains our largest share of production much of our future growth will likely come from the development of our Marcellus Shale play and the exploration of our Utica Shale play.
Coalbed Methane (CBM)
We have the rights to extract CBM in Virginia from approximately 359,000 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 core hole data that allows us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.
We also have the right to extract CBM in northwestern West Virginia and southwestern Pennsylvania from approximately 859,000 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 information that allows us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.
In central Pennsylvania we have the right to extract CBM from approximately 263,000 net CBM acres, which contain most of our recoverable coal reserves as well as significant leases from other coal owners. In addition, we control 810,000 net CBM acres in Illinois, Kentucky, Indiana, and Tennessee. We also have the right to extract CBM on 139,000 net acres in the San Juan Basin, 92,000 net acres in eastern Ohio and central West Virginia, and 20,000 net acres in the Powder River Basin.
Marcellus Shale
We have the rights to extract natural gas in Pennsylvania, West Virginia and New York from approximately 361,000 net Marcellus acres at December 31, 2011. In September 2011, CONSOL Energy entered into a joint venture with Noble Energy regarding our Marcellus Shale oil and gas assets and properties in West Virginia and Pennsylvania. The joint venture holds approximately 628,000 net Marcellus Shale acres in those states as well as the producing Marcellus Shale Wells which we had owned. We hold a 50% interest in the joint venture. We also hold a 50% interest in a related gathering company to which we contributed our existing Marcellus Shale gathering assets. Joint operations are conducted in accordance with a joint development agreement.
CONSOL Energy's Marcellus wells are primarily horizontal wells with 2,500 to 5,000 feet of lateral length. The longer lateral lengths allow for proportionately higher gas production from a single well compared to shorter length lateral wells.
CONSOL Energy continues to develop its Marcellus assets.
Utica Shale
CONSOL Energy also controls approximately 114,000 net acres of Utica Shale potential in southeastern Ohio, southwestern Pennsylvania, and northern West Virginia at December 31, 2011. Additionally, CONSOL Energy controls a large number of acres that contain the rights to the Utica Shale but are disclosed in other plays due to the Utica Shale not being the primary drilling target as of December 31, 2011. The thickness of the Utica Shale in this area ranges from 200 to 450 feet. Further delineation of the Ohio acreage potential exploration play is planned for 2012.
To facilitate the delineation in Ohio, CONSOL Energy entered into a joint venture with Hess Ohio Developments, LLC (Hess) in the fourth quarter of 2011. The Hess joint venture owns approximately 200,000 net acres of Utica Shale rights in Ohio. We hold a 50% interest in the joint venture. Joint operations are conducted in accordance with a joint development agreement.
Shallow Oil and Gas
The shallow oil and gas acreage position of CONSOL Energy is approximately 518,000 net acres mainly in West Virginia, Pennsylvania, Virginia, New York, San Juan Basin and Powder River Basin at December 31, 2011. The majority of our shallow oil and gas leasehold position is held by production and all of it is extensively overlain by existing third party gas gathering and transmission infrastructure. The shallow oil and gas assets provide multiple synergies with our CBM and unconventional shale operations, and the held by production nature of the shallow oil and gas properties affords CONSOL Energy considerable flexibility to choose when to exploit those and other gas assets including shale assets.
Other Gas
We control approximately 346,000 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 2,500-4,000 feet.
The Chattanooga Shale in Tennessee is a Devonian-age shale found at a depth of approximately 3,500 feet. The shale thickness is between 40-80 feet, and CONSOL Energy has found it to be rich in total organic content. CONSOL Energy has 249,000 net acres of Chattanooga Shale. This largely contiguous acreage is composed of only a small number of leases, a rarity in Appalachia. CONSOL Energy is the operator of all of its Chattanooga Shale wells.
We have 457,000 net acres of Huron shale potential in Kentucky, West Virgina, and Virginia; a portion of this acreage has tight sands potential.
Summary of Properties as of December 31, 2011
____________
(1)
Net acres include acreage attributable to our working interests in the properties. 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.
(2)
Acreage amounts are shown under the target strata CONSOL Energy expects to produce, although the reported acre may include rights to multiple gas seams (CBM, Shallow Oil and Gas, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acre in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.
Producing Wells and Acreage
Most of our development wells and proved acreage is located in Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2011, the number of producing wells, developed acreage and undeveloped acreage:
___________
(1)
Net acres include acreage attributable to our working interests in the properties. 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.
Development Wells (Net)
During the years ended December 31, 2011, 2010 and 2009 we drilled 254.9, 317.0 and 247.0 net development wells, respectively. Gob wells and wells drilled by other operators that we participate in are excluded. There were no dry development wells in 2011, one dry development well in 2010, and one dry developmental well in 2009. As of December 31, 2011, forty-seven net developmental wells are still in process. The following table illustrates the net wells drilled by well classification type:
For the year ended December 31, 2011, the Marcellus Segment includes 15 gross developmental wells drilled prior to September 30, 2011. A 50% interest in these wells was subsequently sold to Noble on September 30, 2011. Net developmental wells of 2.5 were drilled after September 30, 2011 under the joint venture agreement and are reflected in the table above at the applicable ownership percentage.
Exploratory Wells (Net)
During the years ended December 31, 2011, 2010 and 2009, we drilled in the aggregate 69.5, 38 and 18 net exploratory wells, respectively. As of December 31, 2011, 2.5 net exploratory wells are still in process. The following table illustrates the exploratory wells drilled by well classification type:
For the year ended December 31, 2011, the Marcellus Segment includes 41 gross exploratory wells drilled prior to September 30, 2011. A 50% interest in these wells was sold to Noble on September 30, 2011. Net exploratory wells of 7.5 were drilled after September 30, 2011 under the joint venture agreement and are reflected in the table above at the applicable ownership percentage.
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). CONSOL Energy has not filed reserve estimates with any federal agency.
___________
(a)
For additional information on our reserves, see “Other Supplemental Information-Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.
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 the 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 of the most directly comparable GAAP measure-after-tax discounted future net cash flows.
Reconciliation of PV-10 to Standardized Measure
Gas Production
The following table sets forth net sales volumes produced for the periods indicated:
Gas Capital Projects
CONSOL Energy plans to spend $473 million on developing its extensive Marcellus Shale assets in 2012. Included in this is drilling capital of $333 million. The budget anticipates that the CONSOL/Noble Energy joint venture will drill 99 (gross) horizontal Marcellus Shale wells, including 39 (gross) wells in the liquids-rich area of the play. CONSOL also expects to invest $77 million in related gathering and compression and $63 million on other related items.
In the CONSOL/Hess joint venture in the Utica Shale, CONSOL Energy expects to invest $53 million in 2012. Most of that will be drilling capital for CONSOL Energy's share of up to 22 gross wells. Most of the Utica drilling is expected to occur in either the liquids-rich area or the oil window of the play.
As a result, the total drilling in the liquids-rich/oil window is expected to be the 39 (gross) wells in the Marcellus Shale, plus the 22 (gross) wells in the Utica Shale, for a total of 61 (gross) wells out of the 121 (gross) wells, or 50%, expected to be drilled in the two plays.
The CBM program will be scaled back in 2012 with the expected drilling of only 86 wells. Total capital for the 2012 CBM program is estimated to be $65 million.
Across all of the gas plays, the $623 million includes $433 million of drilling capital, $108 million of gathering and compression capital, $21 million for production equipment, $23 million for water, $23 million for land and $15 million for other.
As a result of the expected gas investment, CONSOL Energy projects its 2012 gas production to be 160 Bcfe net to CONSOL Energy. This will be an increase of nearly 12%, off of pro forma 2011 production of 142.9 Bcf, adjusted for the partial year impact of Marcellus assets sold to Noble Energy and Antero Resources.
The company expects 2013 gas/liquids production target of between 190 - 210 Bcfe, which will be achieved largely from the ramp-up in drilling in 2012.
The table below summarizes the 2011 actual expenditures made for gas and the forecasted expenditures for 2012.
Gas Sales
Average Sales Price and Average Lifting Cost
The following table sets forth the total average sales price and the total average lifting cost for all of our gas production for the periods indicated, including intersegment transactions. Total lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization. See Part II Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K for a breakdown by segment.
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 enter 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 84.0 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2011 at an average price of $5.21 per thousand cubic feet. These financial hedges represented approximately 52.1 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2010 at an average price of $7.66 per thousand cubic feet. As of December 31, 2011, we expect these transactions will cover approximately 76.9 billion cubic feet of our estimated 2012 production at an average price of $5.25 per thousand cubic feet, 50.8 billion cubic feet of our estimated 2013 production at an average price of $5.06 per thousand cubic feet, 44.0 billion cubic feet of our estimated 2014 production at an average price of $5.20 per thousand cubic feet and 3.8 billion cubic feet of our estimated 2015 production at an average price of $3.97 per thousand cubic feet.
We have purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2011, we have secured firm transportation capacity to cover more than our 2012, 2013 and 2014 hedged production.
The hedging strategy and information regarding derivative instruments used are outlined in Part II Item 7A Qualitative and Quantitative Disclosures About Market Risk and in Note 23 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
Midstream Gas Services
CONSOL Energy has traditionally designed, built and operated natural gas gathering systems to move gas from the wellhead to interstate pipelines or other local sales points. In addition, CONSOL Energy acquired extensive gathering assets in the Dominion Acquisition in 2010. CONSOL Energy now owns or operates approximately 4,000 miles of gas gathering pipelines as well as 230,000 horsepower of compression, of which, approximately 80% is wholly owned with the balance being leased. Along with this compression capacity, CONSOL Energy owns and operates a number of gas processing facilities. This infrastructure is capable of delivering 200 billion cubic feet per year of pipeline quality gas.
On September 30, 2011, in connection with the Noble joint venture for Marcellus wells and leaseholdings, CONE Gathering, LLC was formed. CONSOL Energy and Noble each own 50% of CONE Gathering. CONE Gathering was formed to develop, operate and own both Noble's and CONSOL Energy's Marcellus gathering system needs.
Upon formation of CONE Gathering, CONSOL Energy contributed its then existing Marcellus Shale gathering assets to CONE Gathering. We believe that the network of right-of-ways, vast surface holdings and experience in building and operating gathering systems in the Appalachian basin will give CONE Gathering a tremendous advantage in building the midstream assets required to develop the joint venture's Marcellus position.
CONSOL Energy has had the advantage of having gas production from CBM, which can be lower Btu than pipeline
specification, as well as higher Btu Marcellus production which can complement each other by reducing and in some cases eliminating the need for the costly processing of CBM. In addition, the lower Btu CBM production offers an opportunity to blend ethane back into the gas stream when pricing or capacity for ethane markets dictate. This will allow CONSOL Energy more flexibility in bringing Marcellus on-line at qualities that meet interstate pipeline specifications.
Other Operations
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 water services.
Non-Core Mineral Assets and Surface Properties
CONSOL Energy owns significant coal and gas assets that are not in our short or medium term development plans. We continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures, or a combination of the foregoing in order to bring the value of these assets forward for the benefit of our shareholders. We also control a significant amount of surface acreage. This surface acreage is valuable to us in the development of the gathering system for our Marcellus Shale and Utica Shale production. We also derive value from this surface control by granting rights of way or development rights to third parties when we are able to derive appropriate value for our shareholders.
Industrial Supply Services
Fairmont Supply Company, a CONSOL Energy subsidiary, is a general-line distributor of mining, drilling, and industrial supplies in the United States. Fairmont Supply has 37 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 and drilling supplies to CONSOL Energy's mining and gas operations. Approximately 45% of Fairmont Supply's sales in 2011 were made to CONSOL Energy's coal and gas divisions.
Terminal Services
In 2011, approximately 12.6 million tons of coal were shipped through CONSOL Energy's subsidiary, CNX Marine Terminal Inc.'s, exporting terminal in the Port of Baltimore. Approximately 48% 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 Corporation and CSX Transportation Inc.
River and Dock Services
CONSOL Energy's river operations, located in Monessen, Pennsylvania, transport coal from our mines, coal from other mines and non-coal commodities from river loadout facilities located 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, 2011, we operated 22 towboats, 5 harbor boats and approximately 625 barges. In 2011, our river vessels transported a total of 19.1 million tons of coal and other commodities, including 6.2 million tons of coal produced by CONSOL Energy mines.
CONSOL Energy provides dock services for our mines as well as 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.
Water Services
CNX Water Assets LLC, a CONSOL Energy subsidiary, is acquiring and developing existing sources of water used to support our coal and gas operations. CNX Water Assets LLC, operates an advanced waste water treatment plant in support of coal operations as well as fresh water reservoirs. CNX Water Assets objective is to develop and maximize the value of existing water assets, which will be used to provide water for drilling and hydraulic fracturing in support of gas operations and meeting the needs of mining operations. CNX Water also has contracts to provide water to third parties for industrial use from various water sources owned by CONSOL Energy.
Employee and Labor Relations
At December 31, 2011, CONSOL Energy had 9,157 employees, approximately 32% of whom were represented by the United Mine Workers of America (UMWA). In 2011, the Bituminous Coal Operators Association (BCOA) and the United Mine Workers of America (UMWA) reached a new collective bargaining agreement which will run from July 1, 2011 to December 31, 2016. The National Bituminous Coal Wage Agreement of 2011 (2011 NBCWA) covers approximately 2,900 employees of CONSOL Energy subsidiaries. The 2011 NBCWA is the successor agreement to the 2007 NBCWA that was set to expire on December 31, 2011. Key elements of the new agreement include the following items:
a.
A wage increase of $1.00 per hour effective July 1, 2011, and an additional $1.00 per hour increase each January 1st throughout the contract term.
b.
Contributions to the 1974 Pension Plan, a multi-employer plan, will continue at the current rate of $5.50 per hour throughout the contract term. New inexperienced miners hired after December 31, 2011 will not participate in the 1974 Pension Plan, but will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWA represented employees with over 20 years of credited service under the 1974 Pension Plan will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the CDSP beginning January 1, 2012. Also beginning January 1, 2012, UMWA represented employees will have the right to elect to opt-out of future participation in the 1974 Pension Plan and upon such election, will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014 - 2016) to the CDSP.
c.
A $1.50 per hour contribution starting January 1, 2012 to a new defined contribution plan to provide retiree bonus payments to eligible retirees in 2014, 2015 and 2016.
d.
An increased contribution from $0.50 per hour to $1.10 per hour effective January 1, 2012 to the 1993 Benefit Plan, which is a defined contribution plan providing health benefits to certain retirees.
e.
Various other changes related to absenteeism, contributions to various UMWA benefit funds, eligibility for various vacation days and sick days.
Laws and Regulations
The 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, 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, pipeline compression and transmission of natural gas and liquids, surface subsidence from underground mining, water discharge effluent limits, water appropriation, 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, management of electrical equipment containing polychlorinated biphenyls (PCBs), legislatively mandated benefits for current and retired coal miners, and employee health and safety. 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, all mining operations of CONSOL Energy entities must be maintained in compliance to avoid delay in issuance of necessary mining permits. CONSOL Energy is, or may be, required to prepare and present to federal, state or local authorities data and/or analysis pertaining to the effect or impact that any proposed exploration for or production of coal or gas may have upon the environment, the public and employee health and safety. Permits we need may include requirements that may be subject to future restrictive standards 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.
Compliance with these laws has substantially increased the cost of mining and gas production for all domestic coal and gas producers. 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. 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 against a backdrop of variable geologic and seasonal conditions, permit exceedances and violations during mining and gas production can and do occur. CONSOL Energy made capital expenditures for environmental control facilities of approximately $53.1 million, $39.9 million and $50.4 million in the years ended December 31, 2011, 2010 and 2009, respectively. The capital expenditures for environmental control facilities in 2009 were primarily related to starting construction of an advanced water processing system at the Buchanan Mine. Construction of this facility was completed in 2010. In accordance with a consent decree with the U.S. Environmental Protection Agency and the West Virginia Environmental Protection Agency, CONSOL Energy began construction of an advance water processing system in Northern West Virginia in 2011. Construction is expected to be complete in 2013. Expenditures related to the Northern West Virginia plant of $48.0 million were incurred in 2011 and total costs related to the construction of this plant and related facilities is expected to be approximately $200 million. CONSOL Energy expects to have capital expenditures of $132.2 million in 2012 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 civil penalties 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 refuge 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 replacement of existing seals in worked-out areas of mines with stronger seals;
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the purchase of new fire resistant conveyor belting underground;
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additional training and testing that creates the need to hire additional employees; and
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more stringent rock dusting requirements.
On August 31, 2011, MSHA published a proposed rule, which if adopted, would require proximity protection for miners. The proposed rule would require certain underground mining equipment to be equipped with devices that will shut the equipment down if a person is too close to the equipment to avoid injuries where individuals could be caught between equipment and blocks of unmined coal. MSHA is also considering new rules to reduce the permissible concentration of respirable dust in underground coal mines. This rule, if adopted, would reduce the current standard of two milligrams per cubic meter of air to some lower amount.
Occupational Safety and Health Act
Our gas operations are subject to regulation under the federal Occupational Safety and Health Act (OSHA) and comparable state laws in some states, all of which regulate health and safety of employees at our gas operations. Also, OSHA's hazardous communication standard requires that information be maintained about hazardous materials used or produced by our gas operations and that this information be provided to employees, state and local governments and the public.
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 Patient Protection and Affordable Care Act (PPACA), which was implemented in 2010, made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal
presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner's work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner's death.
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 Plan 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 responsibility for unassigned beneficiaries (referred to as orphans) to the assigned operators. 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 NBCWA or a later NBCWA, and who subsequently goes out of business.
The Act requires some of our signatory 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 those plans. In addition, the NBCWA of 2011 requires our signatory subsidiaries to make specified payments to the 1993 Benefit Plan through 2016. 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 the orphan premium payments due under the 1992 Benefit Plan. Federal contributions were 100% in 2011 and are expected to continue to be 100% after 2011. In addition, federal contributions cover 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 and the 1993 Benefit Plan and certain AML 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 the Combined Fund and 1992 Benefit Plan 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 seven year period. The Pension Act includes a funding target of 100% after 2010. 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 2011 plan year funding ratio of CONSOL Energy's salary retirement plan was 100%. 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 Endangered Species Act,
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the Resource Conservation and Recovery Act,
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the Comprehensive Environmental Response, Compensation and Liability Act,
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the Toxic Substances Control Act, and
•
the Emergency Planning and Community Right to Know Act,
as administered and enforced by the 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. These liabilities may be increased to include 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 Office of Surface Mining (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. All states also impose an obligation on surface mining operations to restore or replace domestic, agricultural or industrial water supplies and on underground mine operations to restore or replace drinking, domestic or residential 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 current per ton fee is $0.315 per ton 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.
OSM is currently considering modifications to the existing stream buffer zone regulation, which amendments are referred to as the Stream Protection Rule. An advanced notice of proposed rulemaking (ANPR) was published in November 2009. Based on the ANPR, the proposed rule would apply to surface mining as well as underground mining activities that may impact streams. Although it is too early to predict what the impacts of the proposed amendments will be, all of the alternatives identified in the ANPR could result in loss of access to significant amounts of coal and/or significant increases in reclamation costs. In Pennsylvania, where CONSOL Energy operates two longwall mines, approximately $29.4 million, $21.8 million and $30.3 million of expenses were incurred during the years ended December 31, 2011, 2010 and 2009, respectively, to mitigate and repair impacts on streams from subsidence. With respect to subsidence impacts to streams, the regulatory requirement to minimize impacts to the hydrologic balance 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 $34.7 million for the year ended December 31, 2012.
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 production and processing operations primarily through permitting and/or emissions control requirements.
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. Carbon dioxide, a greenhouse gas, is also emitted 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.
In 2011, the EPA promulgated or finalized several rulemakings impacting coal generating facilities. These include the Cross-State Air Pollution Rule to regulate sulfur dioxide (SO2), nitrogen dioxide (NOx) and fine particulate matter; and the Utility Maximum Achievable Control Technology (Utility MACT) rule which sets new mercury and air toxic standards and includes more stringent new source performance standards (NSPS) for particulate matter (PM), SO2 and NOX.
In addition, the EPA is proposing to establish NSPS for Green House Gas (GHG) emissions from new electric generating units and proposed regulations to establish GHG emission limits for new and modified electric generating units. The EPA anticipates that a notice of proposed rulemaking (NOPR) will be published in the Federal Register in early 2012. Such regulations could significantly increase the cost of generation of electricity at coal fired facilities and could make competing forms of electricity generation more competitive.
The Clean Air Act and comparable state laws restrict the emission of air pollutants from compressor stations and other equipment and facilities used in our gas operations. We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. In August 2011, the EPA published proposed revisions to the NSPS and proposed revisions to the national emission standards for hazardous air pollutants (NESHAPS) for the Oil and Natural Gas Sector. The EPA intends to issue the final revisions in early 2012. In September 2009, the EPA finalized the Mandatory Reporting of Greenhouse Gas Rule. The current version of this rule requires reporting of emissions from coal mines and gas wells and associated facilities for 2011 emissions.
Clean Water Act
The federal Clean Water Act (CWA) and corresponding state laws affect coal and gas operations by regulating discharges into 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: improvement of designated "impaired waters" (not meeting state water quality standards) through the use of effluent limitations; anti-degradation regulations which protect state designated "high quality/exceptional use" streams by restricting or prohibiting discharges; requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; for minimizing impacts and compensating for unavoidable impacts resulting from discharges of fill materials to regulated streams and wetlands; and the requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. In addition, the Spill Prevention, Control and Countermeasure (SPCC) requirements of the CWA apply to all CONSOL Energy operations that use or produce fluids, including brine and oil, and require that plans be in place to address any spills and that secondary containment be installed around all tanks. These requirements may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.
In order to obtain a permit for surface coal mining activities, including valley fills associated with steep slope mining, an operator must obtain a permit for the discharge of fill material from the Army Corps of Engineers (the COE) pursuant to Section 404 of the Clean Water Act and must obtain a discharge permit from the state regulatory authority under the state counterpart to Section 402 of the Clean Water Act authorizing the issuance of national pollutant discharge elimination permits or NPDES permits. Beginning in early 2009, the EPA took a number of initiatives that have resulted in delays and obstruction of the issuance of such permits for surface mining operation in the states of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia (designated as "Appalachian Surface Coal Mining"). Increased oversight of delegated state programmatic authority, coupled with individual permit review and additional requirements imposed by the EPA, has resulted in delays in the review and issuance of permits for surface coal mining operations, including applications for surface facilities for underground mines, such as applications for coal refuse disposal areas. Thus far, CONSOL Energy subsidiaries have been able to continue operating their existing mines. However, such delays and obstructions in the permitting process may cause CONSOL Energy
to incur additional costs that could adversely affect our operating results, financial condition and cash flows.
Pursuant to a Congressional requirement in the EPA's 2010 budget appropriation, the EPA must conduct a comprehensive study of the potential adverse impact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing is a way of producing gas from tight rock formations such as the Barnett and Marcellus shales. The EPA initiated the study in early January 2011 and plans to make the initial study results available by late 2012, with a final report to Congress soon thereafter. The EPA has also announced plans to conduct a review of water produced in conjunction with the production of Coal Bed Methane (CBM) to determine whether its disposal should be further regulated.
Endangered Species Act
The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans, gas well pad siting or pipeline right of ways, or develop and implement species-specific protection and enhancement 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 or produce gas from our properties.
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. We could incur liability under CERCLA relative to our coal or gas operations. 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 released 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.
The EPA is currently reconsidering the regulation of coal combustion waste, with a decision expected in late 2012. Depending on the outcome of that decision, demand for coal fired electricity generation could be adversely impacted.
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. 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. 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.
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 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 gas 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 siting and construction of well pads and roads, drilling of wells, bonding requirements, protection of ground water and surface water resources and protection of drinking water supplies, the method of drilling and casing wells, the surface use and restoration of well sites, gas flaring, 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. 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
CONSOL Energy acquires ownership or leasehold rights to coal and gas properties prior to conducting operations on those properties. As is customary in the coal and gas industries, we have generally conducted only a summary review of the title to coal and gas rights that are not in our development plans, but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land records to determine control of mineral rights. Given CONSOL Energy's long history as a coal producer, we believe we have a well-developed ownership position relating to our coal control; however, our ownership of oil and gas rights, particularly those rights that we acquired in connection with our historic coal operations, is less developed. As we continue to review our land records and confirm title in anticipation of development, we expect that adjustments to our ownership position (either increases or decreases) will be required.
Prior to the commencement of development operations on coal or gas properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for the cost of curing any title defects. We generally will not commence operations on a property until we have cured any material title defects on such property. We have completed title work on substantially all of our coal and gas producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.
A recent decision by the intermediate appellate court in Pennsylvania in a case captioned Butler v. Powers (Pa. Superior
Ct., No. 1795 MDA 2010) did not change the law of Pennsylvania with respect to the ownership of Marcellus Shale gas rights, but in remanding the case to the trial court for further proceedings, it called into question the applicability of a long-standing presumption known as the Dunham Rule to gas in the Marcellus Shale. The Dunham Rule is a presumption that a reservation or conveyance of minerals does not reserve or convey oil and gas absent an express reference to oil and gas. We believe that the Pennsylvania courts will ultimately confirm that the Dunham Rule applies to Marcellus Shale gas; however, if the Pennsylvania courts were to hold otherwise, we could be exposed to lawsuits challenging our rights to Marcellus Shale gas in some of our Pennsylvania properties where our rights derive from persons who did not also own the mineral rights and we may have to incur substantial additional costs to perfect our gas title in those Pennsylvania properties.
The ownership of CBM is an issue under the laws of some states, including states in which we operate. 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 on Form 10-K.
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. We believe that under Pennsylvania law, a coal lessee under a lease to exhaustion would be in the same position as the coal owner with respect to ownership of the CBM.
Virginia
The Virginia Supreme Court has stated that the grant of coal rights only does not include rights to CBM, absent evidence to the contrary. The situation may be different if there is any expression in the severance deed indicating that more than mere coal is conveyed. Virginia courts have also found that the owner of the CBM does not have the right to fracture the coal in order to retrieve the CBM and that the coal operator has 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 our producing properties. When necessary, we utilize an administrative procedure established by Virginia law that permits 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 within a drilling unit. The general practice is to “force pool” both the coal owner and the gas owner by filing an application with and obtaining an order from the Virginia Gas and Oil Board that permits the development of the CBM in the drilling unit notwithstanding lack of control of the CBM or conflicting claims of ownership. Any royalties otherwise payable to conflicting claimants 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. Several lawsuits are pending in Virginia state courts and several purported class action lawsuits are pending in the Federal District Court for the Western District of Virginia in Abingdon, Virginia, including two lawsuits to which a CONSOL Energy subsidiary is named as a defendant, which seek, among other things, a court order establishing ownership of the CBM relating to the royalties currently held in escrow.
West Virginia
The ownership of CBM is largely an open question in West Virginia. The West Virginia Supreme Court has held that under 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. The West Virginia courts have not further clarified who owns CBM in West Virginia.
West Virginia has enacted 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 force pooling law described above. 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.
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.
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.
Deterioration in the global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets, may have adverse impacts on our business and financial condition that we currently cannot predict.
Economic conditions in a number of industries in which our customers operate, such as electric power generation and steel making, substantially deteriorated in recent years and reduced the demand for natural gas and coal. Although global industrial activity recovered in 2010 from 2009 levels, the continuation of the recovery, especially for industries in the United States and Europe, is uncertain. During recent years, financial markets in the United States, Europe and Asia also experienced unprecedented turmoil and upheaval. This was 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. Although we cannot predict the impacts, renewed weakness in the economic conditions of 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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demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas and thermal coal business;
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demand for metallurgical coal depends on steel demand in the United States and globally, which if weakened would negatively impact the revenues, margins and profitability of our metallurgical coal business including our ability to sell our high volatile steam coal as higher-priced metallurgical coal;
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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 securitization 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 natural 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 natural 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; increased utilization by the steel industry of electric arc furnaces or pulverized coal processes to make steel which do not use furnace coke, an intermediate product produced from metallurgical coal; 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 coal production, which would reduce our revenues.
Gas prices are closely linked to supply of natural gas and consumption patterns in the United States of the electric power 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 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. In particular, while demand for natural gas has recovered to pre-recession levels, the U.S. natural gas industry continues to face concerns of oversupply due to the success of new shale plays and continued drilling in these plays, despite lower gas prices, to meet drilling commitments. 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. These include reduced cash flow, which would decrease funds available for capital expenditures employed to replace reserves or increase production. For example, natural gas prices recently fell to ten year lows and we recently announced a significant reduction in the number of wells expected to be drilled in our Noble joint venture. Also, our 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 an adverse effect on our results of operations in the period taken.
We expect in the future that we and our joint venture partners will increase drilling activity in areas of shale formations which may also contain natural gas liquids and/or oil. The prices for natural gas liquids and oil are volatile for reasons similar to those described above regarding natural gas. If we discover and produce significant amounts of natural gas liquids or oil, our results of operation may be adversely affected by downward fluctuations in natural gas liquids and oil prices.
If coal customers do not extend existing contracts or do not enter into new long-term coal contracts, profitability of CONSOL Energy's operations could be affected.
During the year ended December 31, 2011, approximately 84% 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 in our long-term coal contracts 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, 2011, we derived over 10% of our total revenues from sales to one customer individually and more than 30% of our total revenue from sales to our four largest coal and gas customers. At December 31, 2011, we had approximately seventeen coal supply agreements with these customers that expire at various times from 2012 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.
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 and gas sold and delivered depends on the continued creditworthiness of our customers. Some power plant owners may have credit ratings that are below investment grade. We also have been increasing exports to international customers and may have exposure to their creditworthiness. If the creditworthiness of our customers declines significantly, our $200 million accounts receivable securitization program and our business could be adversely affected. In addition, if customers refuse 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. Similarly, our gas business depends on gathering, processing and transportation facilities owned by others and the disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas.
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.
We gather, process and transport our gas to market by utilizing pipelines and facilities owned by others. If pipelines and facilities do not exist near our producing wells, if pipeline or facility capacity is limited or if pipeline or facility capacity is unexpectedly disrupted, our gas sales could be limited, reducing our profitability. If we cannot access processing pipeline transportation facilities, 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 of gas are reduced because of transportation or processing constraints, our revenues will be reduced, and our unit costs will also increase. If pipeline quality tariffs change, we might be required to install additional processing equipment which could increase our costs. The pipeline could also curtail our flows until the gas delivered to their pipeline is in compliance.
Competition within the coal and natural gas industries may adversely affect our ability to sell our products. Increased competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our coal and natural gas products, 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 electric 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 and wind 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 could encourage 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. We compete with these companies and we may compete with foreign companies for domestic sales. Many of the companies we compete with 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. In addition, larger companies may be able to pay more to acquire new gas properties for future exploration, limiting our ability to replace natural gas we produce or to grow our production. Our ability to acquire additional properties and to discover new natural 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, 2011, we had 9,157 employees. Approximately 32% of these employees are represented by the United Mine Workers of America (UMWA) and represented operations generated approximately 48% of our U.S. coal production during the year ended December 31, 2011. Relations with our employees and, where applicable, organized labor relations are important to our success. If we do not maintain satisfactory labor relations with our organized and non-represented employees, we may incur strikes, other work stoppages or have reduced productivity.
The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plants with alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal for electric power generation could decrease the volume of our coal sales and adversely affect our results of operation.
Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air along with fine particulate matter and carbon dioxide when coal is burned. Complying with regulations on these emissions can be costly for electric power generators. 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 electric power generators switch to alternative fuel could materially affect us. Adoption of the Cross-State Air Pollution Rule (CASPR) in July 2011 (to be effective January 1, 2012, but currently subject to a stay) and the Mercury and Air Toxic Standards Rule (MATS) in December 2011 requiring reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, and particulate matter 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. These additional reductions in permissible emission levels of impurities by coal-fired plants will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future.
Apart from actual and potential regulation of emissions from coal-fired plants, 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 reductions in the amount of coal consumed by domestic electric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.
Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for coal and natural gas and the regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our coal and gas assets.
While climate change legislation in the U.S. is unlikely in the next several years, the issue of 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 emissions into the atmosphere by coal and gas end users, such as coal-fired electric power generation 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. 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. Regulation of GHGs could occur in the United States pursuant to the Environmental Protection Agency (EPA) regulation under the Clean Air Act. On December 23, 2010 the EPA announced that it will propose standards for GHG emissions for gas, oil and coal fired power plants in July 2011 and issue final standards in May 2012. These proposed standards are now scheduled to be published in early 2012. 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 electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants.
If comprehensive regulation focusing on GHGs emission reductions is adopted for the United States by the EPA or in other countries where we sell coal, or if utilities were to have difficulty obtaining financing in connection with coal-fired plants, it may make it more costly to operate fossil fuel fired (especially coal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantially increasing the demand for natural gas. Apart from actual regulation, uncertainty over the regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal or possibly natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal or natural gas and comply with future GHG emission standards.
In addition, coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane has a greater GHG effect 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 further reduce our methane emissions, pay higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines or perhaps curtail coal production. The amount of coalbed methane we capture is reported, on a voluntarily basis, to the U.S. Department of Energy. We have recorded the amounts we have captured since the early 1990's.
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.
Our coal mining and natural gas operations are subject to operating risks, which could increase our operating expenses and decrease our production levels which could adversely affect our results of operations. Our coal and gas operations are also subject to hazards and any losses or liabilities we suffer from hazards which occur in our operations may not be fully covered by our insurance policies.
Our coal mining operations are predominantly underground mines. These mines are subject to a number of operating risks that could disrupt operations, decrease production and increase the cost of mining at particular mines for varying lengths of time thereby adversely affecting our operating results. In addition, if coal production declines, we may not be able to produce sufficient amounts of coal to deliver under our long-term coal contracts. CONSOL Energy's inability to satisfy contractual obligations could result in our customers initiating claims against us. The operating risks that may have a significant impact on our coal operations include:
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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, explosions or other accidents;
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weather conditions; and
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security breaches or terroristic acts.
Our exploration for and production of natural gas also involves numerous operating risks. The cost of drilling, completing and operating our shale gas wells, shallow oil and gas wells and coalbed methane (CBM) wells is often uncertain, and a number of factors can delay or prevent drilling operations, decrease production and/or increase the cost of our gas operations at particular sites for varying lengths of time thereby adversely affecting our operating results. The operating risks that may have a significant impact on our gas operations include:
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in geologic formations;
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equipment failures or repairs;
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fires, explosions or other accidents;
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adverse weather conditions;
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reductions in natural gas prices;
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security breaches or terroristic acts;
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pipeline ruptures;
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lack of adequate capacity for treatment or disposal of waste water generated in drilling, completion and production operations;
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environmental contamination from surface spillage of fluids used in well drilling, completion or operation including fracturing fluids used in hydraulic fracturing of wells, or other contamination of groundwater or the environment resulting from our use of such fluids; and
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unavailability or high cost of drilling rigs, other field services and equipment.
Although we maintain insurance for a number of hazards, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our coal or gas operations.
A decrease in the availability or increase in the costs of commodities or capital equipment used in mining operations could decrease our coal production, impact our cost of coal production and decrease our anticipated profitability.
Coal mining consumes large quantities of commodities including steel, copper, rubber products and liquid fuels and requires the use of capital equipment. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for commodities and capital equipment are strongly impacted by the global market. A rapid or significant increase in the costs of commodities or capital equipment we use in our operations could impact our mining operations costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a ready substitute.
We rely upon third party contractors to provide various field services to our coal and gas operations. A decrease in the availability of or an increase in the prices charged by third party contractors or failure of third party contractors to provide quality services to us in a timely manner could decrease our production, increase our costs of production, and decrease our anticipated profitability.
We rely upon third party contractors to provide key services to our gas operations. We contract with third parties for well services, related equipment, and qualified experienced field personnel to drill wells and conduct field operations. The demand for these field services in the natural gas and oil industry can fluctuate significantly. Higher oil and natural gas prices generally stimulate increased demand causing periodic shortages. These shortages may lead to escalating prices for drilling equipment, crews and associated supplies, equipment and services. Shortages may lead to poor service and inefficient drilling operations and increase the possibility of accidents due to the hiring of inexperienced personnel and overuse of equipment by contractors. 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 increases in the costs of, drilling equipment, crews
and associated supplies, equipment and field services in the future. We also use third party contractors to provide construction and specialized services to our mining operations. A decrease in the availability of field services or equipment and supplies, an increase in the prices charged for field services, equipment and supplies, or the failure of third party contractors to provide quality field services to us, could decrease our coal and gas production, increase our costs of coal and gas production, and decrease our anticipated profitability.
We attempt to mitigate the risks involved with increased industrial activity by entering into “take or pay” contracts with well service providers which commit them to provide field services to us at specified levels and commit us to pay for field services at specified levels even if we do not use those services. However, these contracts expose us to economic risk. For example, if the price of natural gas declines and it is not economical to drill and produce additional natural gas, we may have to pay for field services that we did not use. This would decrease our cash flow and raise our costs of production.
For mining and drilling operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which if we cannot obtain in a timely manner would reduce our production, cash flow and results of operations.
Most coal 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 and interpretation of the laws that regulate mining. The pace with which the 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 and types of surface mining operations 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. These challenges have also enhanced the EPA's oversight and involvement in the review of permits by state regulatory authorities. 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 EPA began to more critically review valley fill permits and permits for all types of coal mining operations, and has been recommending that a number of permits be denied because of alleged concerns by the EPA of potential impacts to water quality in streams below mining operations, with cumulative impacts of mining on watersheds. The EPA's objections and an enhanced review process that was being implemented under a federal multi-agency memorandum of understanding effectively held up the issuance of permits for all types of mining operations that require Clean Water Act Section 402 discharge permits and Section 404 dredge and fill permits, including surface facilities for underground mines. Although a portion of the EPA's enhanced review process was invalidated in October 2011, in part because the EPA failed to follow public notice and rulemaking requirements, normal permitting has not resumed. Also, the EPA may elect to seek to adopt regulations to codify its enhanced review process. CONSOL Energy's surface and underground operations have been impacted to a limited extent to date, but future permits may be delayed if the EPA continues to seek to exercise enhanced oversight and involvement in state permit programs. In addition, 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. These delays or denials of mining permits could reduce our production, cash flow and results of operations.
Existing and future government laws, regulations and other legal requirements relating to protection of the environment, and others that govern our business may increase our costs of doing business for both coal and natural gas, and may restrict both our coal and gas 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. These include 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, threatened and endangered 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, remediation of impacts 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. For example, we have agreed to commence operation by May 30, 2013, of a new advanced waste water treatment plant to treat the discharge of mine water from our Blacksville #2, Loveridge and Robinson Run mines at a total estimated cost of approximately $200 million. In addition, we could incur substantial costs as a result of violations under environmental 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 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 federal regulations and corresponding state laws and regulations require permits for discharges from mining and gas operations that include discharge limits that are adequate to protect existing stream uses and aquatic life and, for impaired streams, that are adequate to eliminate the impairment, which may cause CONSOL Energy to incur 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. In addition, CONSOL Energy incurs and will continue to incur 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.
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 penalties, which would decrease our profitability.
Additionally, regulations applicable to the gas industry are under constant review for amendment or expansion at the federal and state level. Any future changes may affect, among other things, the pricing or marketing of gas production. For example, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as Marcellus shale. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. Hydraulic fracturing is currently exempt from regulation under the federal Safe Drinking Water Act, except for hydraulic fracturing using diesel fuel. The disposal of produced water, drilling fluids and other wastes in underground injection disposal wells is regulated by the EPA under the federal Safe Drinking Water Act or by the states under counterpart state laws and regulations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing operations or to dispose of waste resulting from such operations. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study anticipated to be available by late 2012 and with a final report to be issued in 2014. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (DOE), the U.S. Government Accountability Office and the Department of the Interior. In addition, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Further, some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered or imposed a temporary moratorium on drilling operations using hydraulic fracturing until further study of the potential for environmental and human health impacts by the EPA or the relevant agencies are completed. No assurance can be given as to whether or not similar measures might be considered or implemented in other jurisdictions in which our gas properties are located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in states in which we operate, such legal requirements could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commercially viable. New laws or regulations could also cause delays or interruptions or terminations of operations, the extent of which cannot be predicted, and could reduce the amount of oil and natural gas that we ultimately are able to produce in commercially paying quantities from our gas properties, all of which could have a material adverse affect on our results of operation and financial condition.
Our shale gas drilling and production operations require both adequate sources of water to use in the fracturing process as well as the ability to dispose of water and other wastes after hydraulic fracturing. Our CBM gas drilling and production operations also require the removal and disposal of water from the coal seams from which we produce gas. If we cannot find adequate sources of water for our use or are unable to dispose of the water we use or remove it from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas economically and in commercial quantities could be impaired.
As part of our drilling and production in the Marcellus shale, we use hydraulic fracturing processes. Thus, we need access to adequate sources of water to use in our Marcellus shale operations. Further, we must remove and dispose of the portion of the water that we use to fracture our shale gas wells that flows back to the well-bore as well as drilling fluids and other wastes
associated with the exploration, development or production of natural gas. In addition, in our CBM drilling and production, coal seams frequently contain water that must be removed and disposed of in order for the gas to detach from the coal and flow to the well bore. Our inability to locate sufficient amounts of water with respect to our Marcellus Shale operations, or the inability to dispose of or recycle water and other wastes used in our Marcellus shale and our CBM operations, could adversely impact our operations. For example, in Ohio, injection of gas well production fluids was temporarily suspended for underground injection disposal wells near Youngstown while regulatory authorities investigate whether injection of wastewater into the wells is causing low category earthquakes in the area.
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. A mine could be shut down for an extended period of time if a disaster were to occur at it.
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. If a disaster were to occur at one of our mines, it could be shutdown for an extended period of time and our reputation with our customers could be materially damaged.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share.
We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Our coal refuse areas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory authorities according to stringent environmental and safety standards. Structural failure of a slurry impoundment or coal refuse area could result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
In West Virginia there are areas where drainage from coal mining operations contains concentrations of selenium that without treatment would result in violations of state water quality standards that are set to protect fish and other aquatic life. CONSOL Energy has two operations with selenium discharges. CONSOL Energy and other coal companies are working to expeditiously develop cost effective means to remove selenium from mine water. If such technology is not developed promptly, the only available effective treatment technologies are expensive to construct and operate which will increase coal production costs.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.
CONSOL Energy has reclamation, mine closing 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. Also, state laws require us to plug gas wells and reclaim well sites after the useful life of our gas wells has ended. 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 $650 million at December 31, 2011. 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.
Most states where we operate require us to post bonds for the full cost of coal mine reclamation (full cost bonding). West Virginia is not a full cost bonding state. West Virginia has an alternative bond system (ABS) for coal mine reclamation which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a bond pool (Special Reclamation Fund) funded by a per ton fee on coal mined in the State which is used to supplement the site specific bonds if needed in the event of bond forfeiture. The Special Reclamation Fund is currently underfunded. Adequacy of the Special Reclamation Fund is an issue in a citizen suit pending in U.S. District Court in West Virginia. Given these facts, it is likely that funding for the Special Reclamation Fund will be increased to make it solvent through an increase in the per ton fee or from other funding sources, or the State may be forced by the court or the U.S. Office of Surface Mine Reclamation and Enforcement to convert to full cost bonding. An increase in the per ton fee may reduce profit margins and/or make some operations unprofitable. Conversion to full cost bonding may exceed bonding capacity of individual mining companies and/or surety companies that would result in the need to post cash bonds or letters of credit which would reduce operating capital.
CONSOL Energy faces uncertainties in estimating our economically recoverable coal and gas 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 coal 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 the cost of materials.
In addition, we hold substantial coal reserves in areas containing Marcellus shale and other shales. These areas are currently the subject of substantial exploration for oil and gas, particularly by horizontal drilling. If a well is in the path of our mining for coal, we may not be able to mine through the well unless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater. Horizontal wells with multiple laterals extending from the well pad may access larger oil and gas reserves than a vertical well which could result in higher costs. In future years, the cost associated with purchasing oil and gas wells which are in the path of our coal mining may make mining through those wells uneconomical thereby effectively causing a loss of significant portions of our coal reserves.
Similarly, natural gas reserves require subjective estimates of underground accumulations of natural gas and assumptions concerning natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved gas 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 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 gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of gas 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 gas 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:
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geological conditions;
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changes in governmental regulations and taxation;
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the amount and timing of actual production;
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assumptions governing future prices;
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future operating costs; and
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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 gas reserves as of December 31, 2011 would decrease from $2.9 billion to $2.7 billion. The standardized Generally Accepted Accounting Principle measure associated with this decline of $0.10 per thousand cubic feet, would be approximately $1.7 billion.
Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of coal and gas reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal and gas reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal and gas reserves.
We may incur additional costs and delays to produce coal and gas because we have to acquire additional property rights to perfect our title to coal or gas rights.
While chain of title for our coal estate generally has been established, there may be defects in it that we do not realize until we have committed to developing those properties or coal reserves. As such, the title to the coal estate that we intend to mine may contain defects. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs perfecting title.
Substantial amounts of acreage in which we believe we control gas rights are in areas where we have not yet done a thorough chain of title examination of the gas estate. A number of our gas properties were acquired primarily for the coal rights with the focus on the coal estate title, and, in many cases were acquired years ago. In addition, we have acquired gas rights in substantial acreage from third parties who had not performed thorough chain of title work on their gas properties. Our practice, and we believe industry practice, is not to perform a thorough title examination on gas properties until shortly before the commencement of drilling activities at which time we seek 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.
In confirming title to the gas estate in Pennsylvania, we rely upon long standing Pennsylvania Supreme Court decisions. A recent decision by the intermediate appellate court in Pennsylvania in a case captioned Butler v. Powers (Pa. Superior Ct., No. 1795 MDA 2010) did not change the law of Pennsylvania, but in remanding the case to the trial court for further proceedings, it called into question the applicability of a long-standing presumption known as the Dunham Rule to gas in the Marcellus Shale. The Dunham Rule is a presumption that a reservation or conveyance of minerals does not transfer the ownership of oil and gas absent an express reference to oil and gas. While we believe that the Pennsylvania courts will ultimately confirm that the Dunham Rule applies to Marcellus Shale gas, if the Pennsylvania courts were to hold otherwise, we could be exposed to lawsuits challenging our rights to Marcellus Shale gas in some of our Pennsylvania properties where our
rights derive from persons who did not also own the mineral rights and we may have to incur substantial additional costs to perfect our gas title in those Pennsylvania properties.
Our subsidiaries, primarily Fairmont Supply Company, 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 7,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, New Jersey, Texas 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, 2011, payments by Fairmont with respect to asbestos cases have not been material. Other of our subsidiaries may also have asbestos claims against them. 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 and its subsidiaries are subject to various legal proceedings, which may have an adverse effect on our business.
We are party to a number of legal proceedings in the normal course of business activities. Defending these actions, especially purported class actions, can be costly, and can distract management. For example, we are a defendant in five pending purported class action lawsuits dealing with such diverse matters as the propriety of our acquisition of the noncontrolling interest of CNX Gas, our right to natural gas production in some areas, and asserting that we are responsible for Hurricane Katrina and the damage it caused. There is the potential that the costs of defending litigation in 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-Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.
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, 2011, the current and non-current portions of these obligations included:
•
postretirement medical and life insurance ($3.2 billion);
•
coal workers' black lung benefits ($183.6 million);
•
salaried retirement benefits ($274.8 million); and
•
workers' compensation ($174.1 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 Employer Retirement Income Security Act of 1974 (ERISA) regulations. The other obligations are un-funded. 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 an underfunded multi-employer pension plan, we have exposure under that plan that extends beyond what our obligation would be with respect to our employees and in the future we may have to make additional cash contributions to fund the pension plan or incur withdrawal liability.
Certain of our subsidiaries have been contributing to a multi-employer defined benefit pension plan (1974 Pension Trust) for United Mine Workers of America (UMWA) retirees under the terms of various National Bituminous Coal Wage Agreements (NBCWA) which those subsidiaries have entered into over the years with the UMWA. The current NBCWA with the UMWA became effective July 1, 2011 and expires on December 31, 2016. All assets contributed to the 1974 Pension Trust are pooled
and available to provide benefits for all participants and beneficiaries. As a result, contributions made by our signatory subsidiaries benefit employees of CONSOL Energy and of other employers. For the plan year ended June 30, 2011, approximately 18% of retirees and surviving spouses receiving benefits from the 1974 Pension Trust last worked at signatory subsidiaries of CONSOL Energy. The 1974 Pension Trust is overseen by a board of trustees, consisting of two union-appointed trustees and two employer-appointed trustees. The trustees' responsibilities include selection of the plan's investment policy, asset allocation, individual investment of plan assets and the administration of the plan. The benefits provided by the 1974 Pension Trust to the participating employees are determined based on age and years of service at retirement. The current NBCWA calls for contribution amounts to be paid to the 1974 Pension Trust by our signatory subsidiaries during the term of the NBCWA based principally on hours worked by our UMWA-represented employees at a contribution rate of $5.50 per hour.
As of June 30, 2011, the most recent date for which information is available, the 1974 Pension Trust was underfunded. This determination was made in accordance with Employer Retirement Income Security Act of 1974 (ERISA) calculations, with a total actuarial asset value of $5.1 billion and a total actuarial accrued liability of $6.6 billion. Under the Pension Protection Act of 2006 (Pension Protection Act), a funded percentage of 80% should be maintained for this multi-employer pension plan, and if the plan is determined to have a funded percentage of less than 80% it will be deemed to be “endangered” or “seriously endangered” if the number of years to reach a projected funding deficiency equals 7 or less and if less than 65%, it will be deemed to be in “critical” status. The funded percentage certified by the actuary for the 1974 Pension Trust was determined to be approximately 76.5% under the Pension Act. On October 21, 2011, the signatory subsidiaries of CONSOL Energy received notice from the trustees of the 1974 Pension Trust stating that the 1974 Pension Plan is considered to be in “seriously endangered” status for the plan year beginning July 1, 2011 due to the funded percentage and projected funding deficiency. As a result, the Pension Protection Act requires the 1974 Pension Trust to adopt a funding improvement plan no later than May 25, 2012, to improve the funded status of the plan, which may include increased contributions to the 1974 Pension Trust from employers in the future. Because the 2011 NBCWA established our signatory subsidiaries contribution obligations through December 31, 2016, our signatory subsidiaries' contributions to the 1974 Pension Trust should not increase during the term of the NBCWA as a consequence of any funding improvement plan adopted by the 1974 Pension Trust to address the plan's seriously endangered status.
Upon expiration of the 2011 NBCWA, our signatory subsidiaries could be required to increase contributions to the 1974 Pension Trust in amounts that could be material to our financial position and results of operations or cash flows. In the event our subsidiaries were to withdraw from the 1974 Pension Trust, CONSOL Energy and its subsidiaries 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 information available from the 1974 Pension Trust's administrators, we believe that our portion of the contingent liability represented by the plan's unfunded vested benefits, in the case of the withdrawal of our signatory subsidiaries from the plan or in the case of the termination of the plan, would be material to our financial position and results of operations. As of June 30, 2011 this withdrawal liability was estimated at approximately $1.2 billion. In the event that any other contributing employer withdraws from the 1974 Pension Trust 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 an increase in our proportionate share of the 1974 Pension Trust's unfunded vested benefits at the time of the withdrawal from the plan or its termination.
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 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 reduction in operating results.
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 and to the extent we plan to engage in joint ventures and divestitures, we do not control the timing of these and they may not provide anticipated benefits.
We have completed several acquisitions and investments in the past including the approximately $3.5 billion Dominion
Acquisition, which closed on April 30, 2010. We also 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, we may fail to realize the expected benefits of the acquisition and our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Acquisitions, mine expansion and gas operation expansion 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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the potential revision of assumptions regarding gas reserves as we acquire more knowledge by operating an acquired gas business;
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problems that could arise from the integration of the acquired business;
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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; and
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we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.
From time to time part of our business and financing plans include entering into joint venture arrangements and the divestiture of certain assets. However, we do not control the timing of divestitures or joint venture arrangements and delays in entering into divestitures or joint venture arrangements may reduce the benefits from them. In addition, the terms of divestitures and joint venture arrangements may make a substantial portion of the benefits we anticipate receiving from them to be subject to future matters that we do not control.
We have entered into two significant gas joint ventures. These joint ventures restrict our operational and corporate flexibility; actions taken by our joint venture partners may materially impact our financial position and results of operation; and we may not realize the benefits we expect to realize from these joint ventures.
In the second half of 2011 CONSOL Energy, through its principal gas operations subsidiary, CNX Gas Company LLC (CNX Gas Company), entered into joint venture arrangements with Noble Energy, Inc. (Noble Energy) and Hess Ohio Developments, LLC (Hess) regarding our shale gas assets. We sold a 50% undivided interest in approximately 628 thousand net acres of Marcellus shale oil and gas assets to Noble Energy and a 50% undivided interest in nearly 200 thousand net Utica shale acres in Ohio. The following aspects of these joint ventures could materially impact CONSOL Energy:
•
The development of these properties is subject to the terms of our joint development agreements with these parties and we no longer have the flexibility to control the development of these properties. For example, the joint development agreements for each of these joint ventures sets forth required capital expenditure programs that each party must participate in unless the parties mutually agree to change such programs or, in certain limited circumstances in the case of the Noble Energy joint development agreement, a party elects to exercise a non-consent right with respect to an entire year. If we do not timely meet our financial commitments under the respective joint venture agreements, our rights to participate in such joint ventures will be adversely affected and the other parties to the joint ventures may have a right to acquire a share of our interest in such joint ventures proportionate to, and in satisfaction of, our unmet financial obligations. In addition, each joint venture party has the right to elect to participate in all acreage and other acquisitions in certain defined areas of mutual interest.
•
Each joint development agreement assigns to each party designated areas over which that party will manage and control operations. We could incur liability as a result of action taken by one of our joint venture partners.
•
Of the approximately $3.3 billion we anticipate receiving from Noble Energy, approximately $2.1 billion depends upon Noble Energy paying a portion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess Ohio Developments, LLC (Hess) in which approximately $534 million of the total anticipated consideration of $594 million is dependent upon Hess paying carried costs. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilled and developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third party obligations is outside our control. The inability or failure of a joint venturer to pay its portion of development costs, including our carried costs during the carry period, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss of rights to develop the oil and gas properties held by that joint venture;
•
Noble Energy's obligation to pay carried costs is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per million British thermal units or “MMBtu” in any three consecutive month period and will remain suspended until average natural gas prices are above $4.00/MMBtu for three consecutive months. As a result of this provision, Noble Energy's obligation to pay carried costs was suspended beginning on December 1, 2011. We cannot predict when this suspension will be lifted and Noble Energy's obligation to pay the carried costs will resume. This suspension has the effect of requiring us to incur our entire 50 percent share of the drilling and completion costs for new wells during the suspension period and delaying receipt of a portion of the value we expect to receive in the transaction.
•
The Noble Energy joint development agreement prohibits prior to March 31, 2014, unless Noble Energy consents in its sole discretion, any transfer of our interests in the Noble Energy joint venture assets or our selling or otherwise transferring control of CNX Gas Company. The Hess joint development agreement prohibits prior to October 21, 2014, unless Hess consents in its sole discretion, any transfer of our interests in the Hess joint venture assets. These restrictions may preclude transactions which could be beneficial to our shareholders.
•
Disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.
We may also enter into other joint venture arrangements in the future which could pose risks similar to risks described above.
CONSOL Energy's rights plan may have anti-takeover effects that may discourage a change of control even if doing so might be beneficial to our stockholders.
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 of 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.
The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition and results of operations.
As of December 31, 2011, our total indebtedness was approximately $3.198 billion of which approximately $1.5 billion was under our 8.00% senior unsecured notes due April 2017, $1.25 billion was under our 8.25% senior unsecured notes due April 2020, $250 million was under our 6.375% senior notes due 2021, $103 million was under our Baltimore Port Facility 5.75% revenue bonds due September 2025, $64 million of capitalized leases due through 2021, and $31 million of miscellaneous debt. The degree to which we are leveraged could have important consequences, including, but not limited to:
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increasing our vulnerability to general adverse economic and industry conditions;
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limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our coal and gas reserves or other general corporate requirements;
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limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and gas industries; and
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placing us at a competitive disadvantage compared to less leveraged competitors.
Our senior secured credit facility and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes limit the incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreement, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio, a maximum leverage ratio, and a maximum senior secured leverage ratio, as defined. Our senior secured credit agreement and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, selling assets and engaging in acquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have an adverse effect on us.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our senior secured credit agreement and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.
Unless we replace our gas reserves, our gas 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, 2011, 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 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, 2011, we had hedges on approximately 76.9 billion cubic feet of our 2012 natural gas production, 50.8 billion cubic feet of our 2013 natural gas production, 44.0 billion cubic feet of our 2014 natural gas production, and 3.8 billion cubic feet of our 2015 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:
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our production is less than expected;
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the counterparties to our contracts fail to perform the contracts; or
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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.
Unresolved Staff Comments
None.
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.
Legal Proceedings
The first through the nineteenth paragraphs of Note 24-Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K are incorporated herein by reference.
ITEM 4.
Mine Safety and Health Administration Safety Data
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this annual
report.
PART II
ITEM 5.
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
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, 2011, there were 172 holders of record of our common stock.
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., Chesapeake Energy Corp., Cimarex Energy Co., Comstock Resources Inc., Denbury Resources Inc., Devon Energy Corp., Encana Corp., EOG Resources Inc., James River Coal 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 Westmoreland Coal Co. The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31, 2006. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2011.
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 27, 2012, CONSOL Energy's board of directors declared a regular quarterly dividend of $0.125 per share, payable on February 21, 2012, to shareholders of record on February 7, 2012.
On October 27, 2011, CONSOL Energy's Board of Directors increased the regular annual dividend by 25%, or $0.10 per share, to $0.50 per share, effective immediately.
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 in excess of an annual rate of $0.40 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 2.15 to 1.00 and our availability was approximately $1.2 billion at December 31, 2011. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the year ended December 31, 2011.
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.
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, 2011, 2010, 2009, 2008 and 2007 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, 2011 presentation. 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 annual 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-Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K 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 2,323,230 shares, 2,117,243 shares, 2,127,893 shares, 2,293,581 shares, and 2,099,124 shares for the year ended December 31, 2011, 2010, 2009, 2008, and 2007, respectively.
(C)
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: 0.6 million tons, 0.3 million tons, 0.3 million tons, 1.7 million tons and 0.5 million tons for the years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively.
(D)
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 145, 172, 170, 171 and 179 tons at December 31, 2011, 2010, 2009, 2008 and 2007 respectively. Sales of coal produced by equity affiliates were 0.5 million tons, 0.6 million tons, 0.4 million tons, 0.2 million tons and 0.1 million tons for the years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively. For gas, amounts include 100% of CNX Gas' basis for all years presented; they exclude the noncontrolling interest reduction. There was no equity in affiliates at December 31, 2011, 2010, 2009 and 2008. The proportionate share of proved gas reserves for equity affiliates was 3.6 Bcfe at December 31, 2007. Sales of gas produced by equity affiliates were 0.32 Bcfe for the year ended December 31, 2007.
(E)
Represents proven and probable coal reserves at period end.
(F)
Represents average net sales price including the effect of derivative transactions.
(G)
Represents proved developed and undeveloped gas reserves at period end.
(H)
Net cash used in investing activities includes $485,464 related to the Noble transaction, $190,381 related to the Antero Transaction, and $54,099 related to the Hess Transaction in the year ended December 31, 2011. The year ended December 31, 2010 includes $3,470,212 and $991,034 related to the Dominion Acquisition and the purchase of CNX Gas Non-Controlling Interest, respectively. The year ended December 31, 2007 includes $296,724 related to the acquisition of AMVEST.
(I)
EBIT is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes, loss on debt extinguishment, and abandonment of long-lived assets. 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:
(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.
Management's Discussion and Analysis of Financial Condition and Results of Operations
General
Fourth quarter demand for U.S. thermal and metallurgical coal continued to keep pace with the first three quarters of 2011. Demand for thermal coal from domestic electric generators decreased slightly from the previous year due to decreases in electricity demand and relatively low natural gas prices that have taken some market share from coal generation. International demand for U.S. coals, however, has exceeded any reduction in demand from domestic electric generators. Total U.S. coal exports are likely to exceed 100 million tons for 2011 which is at least 20 million tons higher than 2010 levels.
International demand for U.S. thermal coal slowed in the fourth quarter, but total 2011 thermal coal exports were almost double 2010 levels. Prices for spot coal delivered into Europe declined in the fourth quarter due to weak demand related to the economic slowdown and by weather conditions. Prices for export thermal coal remain competitive relative to U.S. thermal coal customers. Longer-term fundamentals for thermal coal exports to Europe remain favorable as subsidized mining in Europe is phased-out, nuclear growth plans are curtailed and South African coals are pulled into Asian markets.
Domestically, coal inventories at electric generators began to grow towards the end of the fourth quarter due to warmer than normal December weather and relatively low natural gas prices. U.S. electric demand during the fourth quarter of 2011 was estimated to be slightly lower than 2010 levels due to a relatively mild start to the winter season. Coal inventories at electric utilities in CONSOL Energy 's traditional markets grew slightly during the fourth quarter but remain below recent years.
Metallurgical coal demand for 2011 continued the strong pace set earlier this year as world blast furnace output grew an estimated 4.7% over 2010. Steel produced from the blast furnace method uses metallurgical coal and drives metallurgical coal demand. China continues to provide the bulk of the world's blast furnace iron production with almost 59% of world production, an increase of 6.3% compared to 2010. Although European steelmakers have shown signs of a slowdown, global production remains strong. In particular, production in the United States was up almost 13% compared to 2010, supported by a modest rebound in the North American auto sector.
Global supply of metallurgical coal began to normalize in the fourth quarter after conditions improved at Australian mines impacted by the Spring 2011 flooding. International settlement prices have declined since the temporary supply and demand imbalance was resolved, but currently reflect the tight global supply and demand balance for metallurgical coal. CONSOL Energy is well positioned to take advantage of this market with its low cost Buchanan low-volatile operation, low cost high-volatile operations in Northern Appalachia and mid-vol operations set to open in early 2012.
Natural gas markets enjoyed record demand in 2011 primarily driven by gas fired electric generation and an increase in industrial consumption. Some of this increase in demand came from electric generators taking advantage of relatively low prices and utilized more natural gas generation. Supply however, has continued to grow at very strong rates due to the abundance of new shale resources. This supply and demand imbalance is tempered by decreased imports of liquefied natural gas (LNG) and Western Canadian pipeline gas, as well as increased exports to Eastern Canada and Mexico. This supply response may not be sufficient to bring the markets into balance and additional downward price pressures could be experienced in 2012.
Longer-term rebalancing will be aided by declining conventional production and the shift in drilling towards oil and “liquids rich” gas plays. The widespread perception that shale gas production will yield lower and less volatile natural gas prices could spur additional demand as electric generators choose to build additional high-efficiency baseload gas power plants. Additional demand will come from the petrochemical industry and developing sources of demand such as more wide-scale use of natural gas vehicles. CONSOL Energy continues to believe that natural gas will bring balance to CONSOL Energy's portfolio of long-lived energy resources.
A failure to return to normal weather patterns could have a negative short-term impact on CONSOL Energy's natural gas and domestic thermal coal demand. Additionally, uncertainty in the short term economic outlook could lead to a slowing of global economic expansion. Economic uncertainty is currently driven by the European sovereign debt crisis, lingering high U.S. unemployment rates and instability in the Middle East oil-producing region. The fundamental long-term drivers of CONSOL Energy's business remain unchanged as the global demand for low-cost, reliable sources of energy and metallurgical coal remain strong in both the developed and developing world.
CONSOL Energy engaged in several business and financing transactions in the year ended December 31, 2011. These transactions include the following:
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On October 27, 2011, CONSOL Energy's Board of Directors increased the regular annual dividend by 25%, or $0.10 per share, to $0.50 per share.
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On October 21, 2011, CNX Gas Company LLC (CNX Gas Company) completed a sale to a subsidiary of Hess Corporation (Hess) of 50% of its nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54 million, which is net of $5 million of transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $534 million in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. The net gain on the transaction was $53 million and was recognized in the Consolidated Statements of Income as Other Income.
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On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certain Marcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. Cash proceeds of $485 million were received related to this transaction, which are net of $35 million transaction fees. Additionally, a note receivable has been recognized related to the two additional cash payments to be received on the first and a second anniversary of the transaction closing date. The discounted notes receivable of $312 million and $296 million have been recorded in Accounts and Notes Receivables-Notes Receivable and Other Assets-Notes Receivable, respectively. Subsequent to the transaction, an additional receivable of $17 million and a payable of approximately $980 thousand were recorded for closing adjustments and have been included in Accounts and Notes Receivable - Other and Accounts Payable, respectively. The net loss on the transaction was $64 million and was recognized in the Consolidated Statements of Income as Other Income. As part of the transaction, CNX Gas Company also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $2.1 billion with certain restrictions. These restrictions include the suspension of carry if average natural gas Henry Hub prices are below $4.00 per million British thermal units (MMBtu) for three consecutive months. The carry will remain suspended until average natural gas prices are above $4.00/MMBtu for three consecutive months. Restrictions also include a $400 million annual maximum on Noble's carried cost obligation.
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On September 30 2011, CNX Gas Company and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CNX Gas Company's 50% ownership interest in CONE is accounted for under the equity method of accounting. CNX Gas contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $120 million and Noble contributed cash of approximately $68 million. CONE made a cash distribution to CNX Gas in the amount of $68 million. The cash proceeds have been recorded as cash inflows of $60 million and $8 million in Distributions from Equity Affiliates and Proceeds from the Sale of Assets, respectively, on the Consolidated Statements of Cash Flow. The gain on the transaction was $7 million and was recognized in the Consolidated Statements of Income as Other Income.
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On September 21, 2011 CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in approximately 116 thousand net acres of Marcellus Shale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for $193 million. The net gain of $41 million is included in Other Income in the Consolidated Statements of Income.
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CONSOL Energy incurred costs of approximately $15 million in the year ended December 31, 2011 related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020 and 6.375% Senior Notes due 2021. The consents allowed an amendment to the indentures for each of those notes, clarifying that the transactions such as those contemplated by the August 2011 Asset Acquisition Agreements with Noble and Hess were permissible under those indentures.
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In June 2011, the Bituminous Coal Operators Association (BCOA) and the United Mine Workers of America (UMWA) reached a new collective bargaining agreement which will run from July 1, 2011 to December 31, 2016. That agreement, the National Bituminous Coal Wage Agreement of 2011 (2011 NBCWA), covers approximately 2,900 employees of CONSOL Energy subsidiaries. The 2011 NBCWA is the successor agreement to the 2007 NBCWA that was set to expire on December 31, 2011. Key elements of the new agreement include the following items:
a.
A wage increase of $1.00 per hour effective July 1, 2011, and an additional $1.00 per hour increase each January 1st throughout the contract term.
b.
Contributions to the 1974 Pension Plan, a multi-employer plan, will continue at the current rate of $5.50 per hour throughout the contract term. New inexperienced miners hired after December 31, 2011 will not participate in the 1974 Pension Plan, but will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWA represented employees with over 20 years of credited service under the 1974 Pension Plan will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the CDSP beginning January 1, 2012. Also beginning January 1, 2012, UMWA represented employees will have the right to elect to opt-out of future participation in the 1974 Pension Plan and upon such election, will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014 - 2016) to the CDSP.
c.
A $1.50 per hour contribution starting January 1, 2012 to a new defined contribution plan to provide retiree bonus payments to eligible retirees in 2014, 2015 and 2016.
d.
An increased contribution from $0.50 per hour to $1.10 per hour effective January 1, 2012 to the 1993 Benefit Plan, which is a defined contribution plan providing health benefits to certain retirees.
e.
Various other changes related to absenteeism, contributions to various UMWA benefit funds, eligibility for various vacation days and sick days.
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In June 2011, CONSOL Energy management decided to permanently idle its Mine 84 underground facility. This facility had been on idle status since March 2009. Various options for the facility were explored, such as selling and operating with continuous miners, but management decided it was in the best interest of the Company to abandon the underground workings of this facility and reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The Company redeployed all of the movable equipment from the mine that could be used at other locations. The abandonment of this underground facility resulted in a $116 million charge to pre-tax earnings. See Note 10-Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional disclosure. The Company expects the closure of Mine 84 to result in pre-tax cash savings of $18 million per year.
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In April 2011, CNX Gas entered into an amendment to its senior secured credit agreement which increases the
availability under the agreement from $700 million to $1.0 billion, decreases the interest rate and extends the term from May 6, 2014 to April 12, 2016. The amended credit agreement continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries.
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In April 2011, CONSOL Energy amended and extended its existing $1.5 billion senior secured credit agreement, which decreases the interest rate and extends the term from May 7, 2014 to April 12, 2016. The amended agreement continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries.
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On March 9, 2011, CONSOL Energy issued $250 million of 6.375% senior notes due March 2021. The Notes are guaranteed by substantially all of the Company's existing and future wholly owned domestic restricted subsidiaries. The Company issued the Notes with the intention of using the net proceeds to repay its outstanding 7.875% senior secured notes due March 1, 2012, on or before their maturity. On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing the notes. By using the proceeds of the $250 million, 6.375% senior notes due March 2021 to effect this redemption, the Company effectively extended the maturity of the $250 million of long-term indebtedness by nine years at a lower interest rate. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million, for a total redemption cost of approximately $268 million. The loss on extinguishment of debt was approximately $16 million, which primarily represents the interest that would have been paid on these notes if they had been held to maturity.
CONSOL Energy is managing several significant matters that may affect our business and impact our financial results in the future including the following:
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Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel, synthetic rubber and steel that we use in our operations and (ii) increased scrutiny of existing safety regulations and the development of new safety regulations.
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Federal and state environmental regulators are reviewing our operations more closely and more strictly interpreting and enforcing existing environmental laws and regulations, resulting in increased costs and delays. For example, we entered into a consent decree with the U.S. Environmental Protection Agency and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of total dissolved solids in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million.
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Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business. These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules. All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal. Further, other regulations would make it more expensive for our customers to operate their businesses, possibly inducing them to move to alternative fuel sources. For example, the EPA has issued a proposed rule that would regulate coal combustion residuals from coal fired electric generating facilities under the federal Resource Conservation and Recovery Act (RCRA) as either a hazardous waste under Subtitle C of RCRA or as a non-hazardous waste under Subtitle D of RCRA. If final rules are adopted consistent with either of the proposed alternatives, the cost of handling and disposal of coal combustion residuals could increase making it more expensive to generate electricity from coal. Another example is the Cross-State Air Pollution Rule (CSAPR) that was finalized by the EPA on July 6, 2011, although the effective date of the rule has been stayed by a court. CSAPR replaces the Clean Air Interstate Rule and regulates the amount of SO2 and NOx that power plants in 23 eastern states can emit in order to meet clean air requirements in downwind states. Another example is the Mercury and Air Toxic Standards issued by the EPA on December 16, 2011. The new regulations, which will be published in February 2012, set mercury and air toxic standards for new and existing coal and oil fired electric utility steam generating units and include more stringent new source performance standards (NSPS) for particulate matter (PM), SO2 and NOX. Some older coal fired power plants may be retired or have operation time reduced rather than install additional expensive emission controls which could reduce the amount of coal consumed.
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On April 19, 2011, the Pennsylvania Department of Environmental Protection announced its intent to not renew permits for publicly owned treatment works (POTW) that treat municipal wastewater to accept wastewater from
Marcellus Shale operators. They called on operators to cease delivering wastewater to the POTWs by May 19, 2011. CONSOL Energy has implemented a re-cycle and re-use process of its Marcellus derived water for hydraulic fracturing operations, and will only safely dispose of Marcellus wastewater in regulated, underground injection control wells.
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CONSOL Energy continues to explore potential sales of non-core assets.
Results of Operations
Year Ended December 31, 2011 Compared with Year Ended December 31, 2010
Net Income Attributable to CONSOL Energy Shareholders
CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $632 million, or $2.76 per diluted share, for the year ended December 31, 2011. Net income attributable to CONSOL Energy shareholders was $347 million, or $1.60 per diluted share, for the year ended December 31, 2010.
The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $933 million of earnings before income tax for the year ended December 31, 2011 compared to $536 million for the year ended December 31, 2010. The total coal division sold 62.7 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates, for the year ended December 31, 2011 compared to 63.0 million tons for the year ended December 31, 2010.
The average sales price and average costs per ton for all active coal operations were as follows:
The higher average sales price per ton sold reflects successful re-negotiation of several domestic thermal contracts whose pricing took effect January 1, 2011, another strong quarter of high volatile metallurgical coal sales and demand for our premium low volatile metallurgical coal. Also, 11.7 million tons were priced on the export market at an average sales price of $121.29 per ton for the year ended December 31, 2011 compared to 8.1 million tons at an average price of $97.10 per ton for the year ended December 31, 2010.
Average costs per ton sold increased $5.30 per ton in the period-to-period comparison due primarily to the following:
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Operating supplies and maintenance costs per ton sold were higher due to increased equipment overhauls, additional roof control and additional equipment maintenance.
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Depreciation, depletion and amortization increased due to additional assets placed into service after the 2010 period.
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Labor and labor related charges increased as a result of additional employees, increased overtime hours worked and the impact of the $1.50 per hour worked UMWA contract wage increases, $0.50 per hour worked related to the prior UMWA contract and $1.00 per hour worked related to the July 2011 UMWA contract.
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Other post employment benefits and pension expenses increased primarily due to changes in discount rates, employees retiring sooner than originally anticipated and higher average claim costs.
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Royalties and production related taxes increased due to higher sales price of coal sold.
The total gas division includes coalbed methane (CBM), shallow oil and gas, Marcellus and other gas. The total gas division contributed $130 million of earnings before income tax for the year ended December 31, 2011 compared to $180 million for the year ended December 31, 2010. Total gas production was 153.5 billion net cubic feet for the year ended December 31, 2011 compared to 127.9 billion net cubic feet for the year ended December 31, 2010. Total gas production increased primarily due to the on-going drilling program partially offset by 6.6 billion net cubic feet of production related to the Noble joint venture.
The average sales price and average costs for all active gas operations were as follows:
Total gas division outside sales revenues were $752 million for the year ended December 31, 2011 compared to $746 million for the year ended December 31, 2010. The increase was primarily due to 20.0% increase in volumes sold partially offset by the 16.0% reduction in average price per thousand cubic feet sold. The volume increase was primarily due to additional wells drilled under the on-going drilling program, and additional volumes from the wells purchased in the Dominion Acquisition, which occurred on April 30, 2010 offset, in part, by the impact of the Noble joint venture which reduced 2011 volumes by approximately 6.6 billion net cubic feet. The decrease in average sales price is the result of various gas swap transactions that occurred throughout both periods and lower average market prices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 84.0 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2011 at an average price of $5.21 per thousand cubic feet. These financial hedges represented 52.1 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2010 at an average price of $7.66 per thousand cubic feet.
Total gas unit costs decreased slightly for the year ended December 31, 2011 compared to the year ended December 31, 2010 primarily due to lower depreciation, depletion and amortization and lower gathering costs partially offset by increased lifting costs. The wells purchased in the Dominion Acquisition increased total operating costs by $0.32 per thousand cubic feet due to higher costs and lower volumes produced related to the age of these wells compared to the legacy CONSOL Energy wells. Excluding the impact of these purchased wells, unit costs improved $0.36 per thousand cubic feet primarily due to the additional volumes produced, improved depreciation, depletion and amortization and lower gathering charges. Volumes increased in the period-to-period comparison due to the on-going drilling program and the additional volumes from the wells purchased in the Dominion Acquisition partially offset by the impact of the Noble joint venture. Lower depreciation, depletion and amortization rates were the result of additional gas reserves recognized at December 31, 2010. Gathering and compression charges were improved primarily due to a fuel surcharge reduction by a utility provider. Lifting costs increased in the period-to-period comparison due to additional well services to maintain production levels.
The other segment includes industrial supplies activity, terminal, river and dock service activity, income taxes and other business activities not assigned to the coal or gas segment.
Included in both coal and gas unit costs are Selling, General and Administrative Expenses and total Company long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation and long-term disability. Total Company Selling, General and Administrative Expenses are allocated to various segments primarily based on revenue and capital expenditure projections between coal and gas as a percent of total. Total Company Selling, General and Administrative Expenses were made up of the following items:
Total Company Selling, General and Administrative Expenses increased due to the following:
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Employee wages and related expenses increased $8 million which was primarily attributable to the support staff retained in the Dominion Acquisition and additional hiring of support staff in the period-to-period comparison.
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Demurrage charges were higher in the 2011 period due to increased export traffic at the Baltimore terminal.
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Advertising and promotion expense increased $3 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.
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Contributions expense increased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.
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Commission expense increased $2 million due to the increase in average sales price and additional tons sold for which a third party was owed a commission in the period-to-period comparison.
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Consulting and professional services increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
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Miscellaneous selling, general and administrative expenses increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.
Total Company long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy expense related to our actuarial calculated liabilities was $332 million for the year ended December 31, 2011 compared to $287 million for the year ended December 31, 2010. The increase of $45 million was due primarily to OPEB and salary pension expense. The additional OPEB and salary pension expense related to changes in discount rates, employees retiring sooner than originally anticipated and higher average claim costs. See Note 15-Pension and Other Postretirement Benefit Plans and Note 16-Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-k for additional details related to total Company expense increases.
TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2011 compared to the year ended December 31, 2010:
The coal segment contributed $933 million of earnings before income tax in the year ended December 31, 2011 compared to $536 million in the year ended December 31, 2010. Variances by the individual coal segments are discussed below.
THERMAL COAL SEGMENT
The thermal coal segment contributed $456 million to total Company earnings before income tax for the year ended December 31, 2011 compared to $461 million for the year ended December 31, 2010. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:
Thermal coal revenue was $3,058 million for the year ended December 31, 2011 compared to $3,001 million for the year ended December 31, 2010. The $57 million increase was attributable to a $5.11 per ton higher average sales price partially offset by 3.8 million fewer tons sold in 2011. The higher average thermal coal sales price in the 2011 period was the result of the successful re-negotiation of several domestic thermal contracts whose pricing took effect on January 1, 2011. Also, 2.8 million tons of thermal coal was priced on the export market at an average sales price of $66.45 per ton for the year ended December 31, 2011 compared to 2.4 million tons at an average price of $54.68 per ton for year ended December 31, 2010. The thermal coal segment was also impacted by 4.7 million tons of thermal coal sold on the high volatile metallurgical coal market for the year ended December 31, 2011, which was 2.3 million tons more than the tons sold in the year ended December 31, 2010.
Other income attributable to the thermal coal segment represents earnings from our equity affiliates that operate thermal coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.
Operating costs are comprised of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the thermal coal segment were $1,919 million for the year ended December 31, 2011 compared to $1,934 million for the year ended December 31, 2010. Operating costs related to the thermal coal segment decreased primarily due to lower volumes sold partially offset by higher average costs per ton sold.
Changes in the average operating costs per ton for thermal coal sold were also related to the following items:
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Average operating supplies and maintenance costs per thermal ton sold increased due to additional maintenance and equipment overhaul costs, additional roof control costs, and increased fuel and lubricants. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers. Increased fuel and lubricant costs are related to higher fuel prices in the current period.
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Labor and related benefits were impaired on a cost per thermal ton sold basis due to higher costs and lower volumes sold. Higher benefit costs were due primarily to contributions made to the 1974 Pension Trust (the Trust), which is a multiemployer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement and are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Non-represented benefit rates for active employees also increased as a result of continued increases in healthcare costs. Labor and related benefits also increased due to additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the July 2011 collective bargaining agreement. These increases were offset, in part, as a result of the Tax Relief and Health Care Act of 2006 authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Plan and the 1993 Plan. The additional federal funding eliminated the 2011 funding of orphan retirees by participating active employers of the plans, resulting in lower expense in the
period-to-period comparison. The additional federal funding does not impact the amount of contributions required to be paid for our assigned retirees. Also, we may be required to make additional payments in the future to these plans in the event the federal contributions are not sufficient to cover the benefits.
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Production taxes average cost per thermal ton sold increased primarily due to the $5.11 per ton higher average sales price.
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Average operating costs per thermal ton sold increased due to lower tons sold resulting in fixed costs being allocated over less tons resulting in higher unit costs.
Provision costs are made up of the expenses related to the Company's long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation, long-term disability and accretion on mine closing and related liabilities. With the exception of accretion expense on mine closing and related liabilities, these liabilities are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. Provision costs attributable to the thermal coal segment were $220 million for the year ended December 31, 2011 compared to $198 million for the year ended December 31, 2010. The increased thermal coal provision expense was attributable to the total Company increase in long-term liability expense discussed in the total Company results of operations section. Thermal coal accretion expense related to mine closing and related liabilities remained consistent in the period-to-period comparison.
Selling, administrative and other costs attributable to the thermal coal segment include selling, general and administrative expenses and direct administrative costs. Selling, general and administrative costs, excluding commission expense, are allocated to various segments based on a combination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal division of the business and are allocated to various mines based on a combination of estimated time worked and production. Selling, administrative and other costs related to the thermal coal segment were $167 million for the year ended December 31, 2011 compared to $142 million for the year ended December 31, 2010. The cost increases attributable to the thermal coal segment were attributable to higher selling, general and administrative expenses as discussed in the total Company results of operations section and higher direct administrative costs. Higher direct administrative costs were primarily due to higher employee related expenses due to additional support staff requirements, increased safety reward expense and increased coal sampling charges in the period-to-period comparison. These higher costs and lower sales volumes resulted in a $0.66 per ton increase in average cost per ton sold.
Depreciation, depletion and amortization for the thermal coal segment was $302 million for the year ended December 31, 2011 compared to $274 million for the year ended December 31, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the 2010 period that was depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for thermal coal mines due to additional air shafts being placed into service after the 2010 period which had higher unit rates than historical shafts put into service. These higher expenses and lower sales tons, resulted in a $0.91 increase in average costs per ton sold.
HIGH VOL METALLURGICAL COAL SEGMENT
The high volatile metallurgical coal segment contributed $135 million to total Company earnings before income tax for the year ended December 31, 2011 compared to $87 million for the year ended December 31, 2010. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:
High volatile metallurgical coal revenue was $368 million for the year ended December 31, 2011 compared to $172 million for the year ended December 31, 2010. Strength in the metallurgical coal market has continued to allow the export of Northern Appalachian coal, historically sold domestically on the thermal coal market, to crossover to the Brazilian and Asian metallurgical coal markets. Also, 4.3 million tons of thermal coal was priced on the export market at an average sales price of $77.48 per ton for the year ended December 31, 2011 compared to 2.3 million tons at an average price of $73.51 per ton for year ended December 31, 2010. As a result, average sales prices for high volatile metallurgical coal have increased due to growing the base of end user customers.
Other income attributed to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate high volatile metallurgical coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.
Operating costs related to the high volatile metallurgical coal segment were $175 million for the year ended December 31, 2011 compared to $69 million for the year ended December 31, 2010. Operating costs related to the high volatile metallurgical coal segment increased primarily due to higher volumes sold and higher average costs per ton sold.
Changes in average operating costs per ton for high volatile metallurgical coal sold were primarily related to the following items:
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Average operating costs per high volatile metallurgical ton sold increased due to the mix of mines selling coal on the high volatile metallurgical coal market. As higher cost structure mines sell coal in the high volatile metallurgical market, average operating costs per ton sold increase. Previously, this segment only included lower cost structure mines.
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Labor and related benefits increased due to higher employee counts, higher non-represented benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Labor and related benefits increased due to additional employees in the period-to-period comparison. Higher labor and related costs were also due to higher non-represented benefit rates for active employees related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the thermal coal segment. Labor and related benefits also increased due to the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the July 2011 collective bargaining agreement, in the period-to-period comparison. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the thermal coal segment. Increased labor and related benefit costs per unit sold were also offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.
•
Average operating supplies and maintenance costs per high volatile metallurgical ton sold increased due to additional maintenance and equipment overhaul costs, additional roof control costs, and increased fuel and lubricants. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers.
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Average coal preparation costs per high vol ton sold increased due to additional maintenance projects that have been completed at our preparation plants in the period-to-period comparison.
•
Production taxes average cost per high volatile metallurgical ton sold increased due to the $5.17 per ton higher average sales price.
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In-transit charges average cost per high volatile metallurgical ton sold increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the mix of mines now shipping high volatile metallurgical coal.
The provision expense attributable to the high volatile metallurgical coal segment was $20 million for the year ended December 31, 2011 compared to $7 million for the year ended December 31, 2010. The increase in the high volatile metallurgical coal provision expense was attributable to the total Company increased long-term liability expense discussed in the total Company results of operations section. The per unit impairment was offset, in part, by additional tons sold in the period-to-period comparison. Also, high volatile metallurgical coal accretion expense related to mine closing and related liabilities remained consistent in the period-to-period comparison which offset some increases in costs per ton sold.
Selling, administrative and other costs attributable to the high volatile metallurgical coal segment include selling, general and administrative expenses and direct administrative costs. Selling, general and administrative expenses, excluding commission expense, are allocated to various segments based on a combination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal division of the business and are allocated to various mines based on a combination of estimated time worked and production. Selling, administrative and other costs related to the high volatile metallurgical coal segment were $18 million for the year ended December 31, 2011 compared to $5 million for the year ended December 31, 2010. The cost increase attributable to the high volatile metallurgical coal segment is attributable to higher total Company selling, general and administrative expenses as discussed in the total Company results of operations section and higher direct administrative costs. Higher direct administrative costs were primarily due to higher employee related expenses due to additional support staff requirements, increased safety reward expense and increased coal sampling charges in the period-to-period comparison. These additional expenses increased unit costs per ton sold and were offset, in part, by higher volumes of high volatile metallurgical coal sold.
Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $31 million for the year ended December 31, 2011 compared to $11 million for the year ended December 31, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the 2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for high volatile metallurgical coal mines related to additional air shafts being placed into service after the 2010 period which had higher unit rates than historical shafts put into service. These increases in unit costs per ton sold were offset, in part, by additional high volatile metallurgical tons sold which lowered the unit cost per ton impact.
The high volatile metallurgical coal segment increased the margin on our coal production that would have otherwise been sold in the domestic thermal coal market.
LOW VOL METALLURGICAL COAL SEGMENT
The low volatile metallurgical coal segment contributed $681 million to total Company earnings before income tax in the year ended December 31, 2011 compared to $382 million in the year ended December 31, 2010. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:
Low volatile metallurgical coal revenue was $1,072 million for the year ended December 31, 2011 compared to $680 million for the year ended December 31, 2010. The $392 million increase was attributable to a $45.49 per ton higher average sales price due to the strength of the low volatile metallurgical market, both domestic and foreign. The strength of these markets is related to continued worldwide demand for premium low volatile metallurgical coal. For the 2011 period, 4.6 million tons of low volatile metallurgical coal was priced on the export market at an average price of $196.46 per ton compared to 3.3 million tons at an average price of $144.23 per ton for the 2010 period.
Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the low volatile metallurgical coal segment were $288 million for the year ended December 31, 2011 compared to $232 million for the year ended December 31, 2010. Operating costs related to the low volatile metallurgical coal segment increased primarily due to higher volumes sold.
Changes in the average operating costs per ton for low volatile metallurgical coal sold were primarily related to the following items:
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Production taxes average cost per low volatile metallurgical ton sold increased due to the $45.49 per ton higher average sales price.
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Average operating supplies and maintenance costs per low volatile metallurgical ton sold increased due to additional roof control costs, additional ventilation costs of coalbed methane gas, additional equipment overhaul costs and increased rock dusting. Additional roof control costs resulted from changes in roof support strategy, such as types of roof support used and quantity of supports put into place. The roof control strategy was changed to improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. In addition, costs were incurred in the 2011 period to increase the number of bore holes that were placed ahead of mining to ventilate the coalbed methane gas from the mine. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Increased rock dusting was primarily due to changes in regulations.
These increases in costs were partially offset by the following items:
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Coal inventory volumes increased slightly at December 31, 2011 compared to December 31, 2010 and carrying value increased $5.09 per ton in the corresponding period. Coal inventory decreased 0.2 million tons at December 31, 2010 compared to December 31, 2009 and the carrying value of the inventory during the corresponding period increased $7.29 per ton. These changes in inventory caused a reduction in average operating cost per ton sold in the period-to-period comparison.
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Power costs per low volatile metallurgical ton sold were improved due to utility rate reductions that became effective in the 2011 period.
The provision expense attributable to the low volatile metallurgical coal segment was $38 million for the year ended December 31, 2011 compared to $27 million for the year ended December 31, 2010. The increased low volatile metallurgical
coal provision expense per ton sold was attributable to the total Company's increased long-term liability expense discussed in the total Company results of operations section, offset, in part, by higher volumes of low volatile metallurgical coal sold. Low volatile metallurgical coal accretion expense related to mine closing and related liabilities decreased approximately $1 million in the period-to-period comparison as a result of the annual engineering surveys which contributed to lower average costs per ton sold.
Selling, administrative and other costs attributable to the low volatile metallurgical coal segment include selling, general and administrative expenses, direct administrative costs and water treatment expenses generated from the reverse osmosis plant. Selling, general and administrative costs, excluding commission expense and water treatment expense, are allocated to various segments on a combination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal division of the business and are allocated to various mines based on a combination of estimated time worked and production. Selling, administrative and other costs related to the low volatile metallurgical coal segment were $28 million for the year ended December 31, 2011 compared to $18 million for the year ended December 31, 2010. The cost increase related to the low volatile metallurgical coal segment was attributable to higher selling, general and administrative expenses as discussed in the total Company results of operations section. Also, a reverse osmosis plant was completed and placed into service near the Buchanan Mine. Active mine water discharge is being treated by this facility and the costs of these services are charged to the mine based on gallons of water treated. Currently, the Buchanan Mine is the only facility using the plant. Construction of the plant was completed and the plant was placed into service in January 2011. These increases in expense were offset, in part, by higher volumes of low volatile metallurgical coal sold.
Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $37 million for the year ended December 31, 2011 compared to $21 million for the year ended December 31, 2010. The increase was primarily due to additional equipment, infrastructure and the reverse osmosis plant placed into service after the 2010 period that is depreciated on a straight-line basis. These increases in average costs per ton sold were offset, in part, by higher low volatile metallurgical tons sold which lowered the unit cost per ton impact.
OTHER COAL SEGMENT
The other coal segment had a loss before income tax of $339 million for the year ended December 31, 2011 compared to a loss before income tax of $394 million for the year ended December 31, 2010. The other coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.
Other coal segment produced coal sales includes revenue from the sale of 0.4 million tons of coal which was recovered during the reclamation process at idled facilities for the year ended December 31, 2011 compared to 0.2 million tons for the year ended December 31, 2010. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold are incidental to total Company production or sales.
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 revenues were $42 million for the year ended December 31, 2011 compared to $34 million for the year ended December 31, 2010. The increase was primarily due to increased volumes sold partially offset by a decrease in the average sales price.
Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is almost completely offset in freight expense. Freight revenue was $232 million for the year ended December 31, 2011 compared to $126 million for the year ended December 31, 2010. The increase in freight revenue was primarily due to the 3.6 million ton increase in export tons in the period-to-period comparison.
Miscellaneous other income was $62 million for the year ended December 31, 2011 compared to $48 million for the year ended December 31, 2010. The increase of $14 million was primarily related to issuing pipeline right-of-ways to third parties which resulted in a gain of $12 million and various other transactions that occurred throughout both periods, none of which were individually material.
Other coal segment total costs were $702 million for the year ended December 31, 2011 compared to $614 million for the year ended December 31, 2010. The increase of $88 million was due to the following items:
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Abandonment of long-lived assets was $116 million for the year ended December 31, 2011 as a result of permanently idling Mine 84.
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Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is almost completely offset in freight revenue. The increase was primarily due to the 3.6 million ton increase in export tons in the period-to-period comparison.
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Purchased coal costs increased approximately $31 million in the period-to-period comparison primarily due to differences in the quality of coal purchased, increases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.
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Coal contract buyout costs increased $5 million as a result of a lower priced coal sales contract being bought out in order to sell the tons at a higher price in a future period.
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Closed and idle mine costs decreased approximately $115 million in the year ended December 31, 2011 compared to the year ended December 31, 2010. In the 2010 period, as a result of market conditions, permitting issues, new regulatory requirements and the resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia increased $82 million. Also in the 2010 period, closed and idle mine costs increased approximately $14 million as the result of the change in mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine was abandoned. Closed and idle mine costs decreased $9 million as a result of the decision to permanently abandon Mine 84. Closed and idle mine costs for the 2010 period also included $6 million related to various asset abandonments that occurred, none of which were individually material. In addition, $9 million of reduced expenses were recognized in closed and idle mine costs for various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which were individually material. Closed and idle mine costs increased $5 million in the 2011 period due to a charge for an additional liability due to Pennsylvania stream remediation.
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Litigation expense of $25 million was recognized in the year ended December 31, 2010 related to a legal settlement related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. Litigation expense was also recognized in the year ended December 31, 2010 related to a settlement that included the sale of Jones Fork which resulted in a loss of $10 million. Litigation expense related to various other potential legal settlements decreased $12 million in the period-to-period comparison. None of these items were individually material.
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Other costs related to the coal segment decreased $7 million due to various other transactions that occurred throughout both periods, none of which are individually material.
TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2011 compared to the year ended December 31, 2010:
The gas segment contributed $130 million to earnings before income tax for the year ended December 31, 2011 compared to $180 million for the year ended December 31, 2010.
COALBED METHANE (CBM) GAS SEGMENT
The CBM segment contributed $154 million to the total Company earnings before income tax for the year ended December 31, 2011 compared to $248 million for the year ended December 31, 2010.
CBM sales revenues were $466 million for the year ended December 31, 2011 compared to $573 million for the year ended December 31, 2010. The $107 million decrease was primarily due to a 19.5% decrease in average sales price per thousand cubic feet sold, offset, in part, by a 1.1% increase in average volumes sold. The decrease in CBM average sales price is the result of various gas swap transactions that matured in each period and lower average market prices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 61.8 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2011 at an average price of $5.36 per thousand cubic feet. For the year ended December 31, 2010, these financial hedges represented 50.5 billion cubic feet at an average price of $7.73 per thousand cubic feet. CBM sales volumes increased 1.0 billion cubic feet primarily due to additional wells coming on-line from our on-going drilling program. At December 31, 2011 and 2010 there were 4,262 and 4,020 CBM wells in production, respectively.
Total costs for the CBM segment were $312 million for the year ended December 31, 2011 compared to $325 million for the year ended December 31, 2010. Lower costs in the period-to-period comparison are primarily related to lower unit costs.
CBM lifting costs were $52 million for the year ended December 31, 2011 compared to $50 million for the year ended December 31, 2010. Lifting costs increased primarily due to increased road maintenance, additional tank repairs, and additional maintenance on older wells.
CBM gathering costs were $98 million for the year ended December 31, 2011 compared to $97 million for the year ended December 31, 2010. CBM gathering unit costs remained consistent in the period-to-period comparison.
General and direct administrative costs attributable to the total gas division were $112 million for the year ended December 31, 2011 compared to $93 million for the year ended December 31, 2010. The $19 million increase was attributable to additional corporate service charges from CONSOL Energy and additional staffing. Corporate service charge allocations are primarily based on revenue and capital expenditure projections between coal and gas as a percent of total. The additional staffing is primarily due to the majority of the operational support staff being retained from the Dominion Acquisition which closed on April 30, 2010.
General and direct administrative costs for the CBM segment were $61 million for year ended December 31, 2011 compared to $65 million for the year ended December 31, 2010. General and direct administrative costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. Lower general and direct administrative costs attributable to the CBM segment was attributable to the increase in other gas segment volumes.
Depreciation, depletion and amortization attributable to the CBM segment was $101 million for the year ended December 31, 2011 compared to $113 million for the year ended December 31, 2010. There was approximately $72 million, or $0.78 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2011. The production portion of depreciation, depletion and amortization was $87 million, or $0.98 per unit-of-production in the year ended December 31, 2010. The CBM unit-of-production rate decreased due to revised rates which are generally calculated using the net book
value of assets divided by either proved or proved developed reserve additions. There was approximately $29 million, or $0.32 average per unit cost of depreciation, depletion and amortization relating to gathering and other equipment reflected on a straight line basis for the year ended December 31, 2011. The non-production related depreciation, depletion and amortization was $26 million, or $0.27 per thousand cubic feet for the year ended December 31, 2010. The increase was related to additional gathering assets placed in service after the 2010 period.
SHALLOW OIL AND GAS SEGMENT
The shallow oil and gas segment had a loss before income tax of $23 million for the year ended December 31, 2011 compared to a loss before income tax of $4 million for the year ended December 31, 2010.
Shallow Oil and Gas sales revenues were $155 million for the year ended December 31, 2011 compared to $116 million for the year ended December 31, 2010. The $39 million increase was primarily due to the 30.4% increase in volumes sold as well as the 2.1% increase in average sales price. Shallow Oil and Gas sales volumes increased 7.5 billion cubic feet in the year ended December 31, 2011 compared to the 2010 period primarily due to the Dominion Acquisition, which closed on April 30, 2010. Approximately 95% of the acquired producing wells were Shallow Oil and Gas type wells. Average sales price increased primarily as the result of various gas swap transactions that matured in the year ended December 31 2011, offset, in part by lower average market prices. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 11.5 billion cubic feet of our produced Shallow Oil and Gas gas sales volumes for the year ended December 31, 2011 at an average price of $4.97 per thousand cubic feet. There were no Shallow Oil and Gas gas swap transactions that occurred in the year ended December 31, 2010. There were 8,041 and 8,016 shallow oil and gas wells in production at December 31, 2011 and 2010, respectively.
Shallow Oil and Gas lifting costs were $60 million for the year ended December 31, 2011 compared to $30 million for the year ended December 31, 2010. Lifting costs per unit increased $0.62 per thousand cubic feet sold primarily due to increased road maintenance, increased well site maintenance, increased salt water disposal and additional well services performed to maintain production levels.
Shallow Oil and Gas gathering costs were $27 million for the year ended December 31, 2011 compared to $18 million for the year ended December 31, 2010. Average gathering costs increased $0.08 per unit primarily due to additional compressor maintenance.
General and direct administrative costs for the Shallow Oil and Gas gas segment were $30 million for the year ended December 31, 2011 compared to $22 million for the year ended December 31, 2010. General and direct administrative costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The total general and direct administrative costs increases which were discussed in the CBM segment and higher volumes of Shallow Oil and Gas gas sold contributed to the increase in the Shallow Oil and Gas gas segment. General and direct administrative costs were $0.94 per thousand cubic feet sold for the year ended December 31, 2011 compared to $0.88 per thousand cubic feet sold for the year ended December 31, 2010.
Depreciation, depletion and amortization costs were $61 million for the year ended December 31, 2011 compared to $50 million for the year ended December 31, 2010. There was approximately $54 million, or $1.69 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2011. There was approximately $45 million, or
$1.84 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the year ended December 31, 2010. The rate was calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. There was approximately $7 million, or $0.23 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the year ended December 31, 2011. There was $5 million, or $0.19 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the year ended December 31, 2010. The increase was related to additional infrastructure and equipment placed in service after the 2010 period.
MARCELLUS GAS SEGMENT
The Marcellus segment contributed $36 million to the total Company earnings before income tax for the year ended December 31, 2011 compared to $6 million for the year ended December 31, 2010.
The Marcellus segment sales revenues were $119 million for the year ended December 31, 2011 compared to $49 million for the year ended December 31, 2010. The $70 million increase was primarily due to a 158.7% increase in average volumes sold, offset, in part, by a 5.5% decrease in average sales price per thousand cubic feet sold. The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program, partially offset by 6.6 billion cubic feet related to the Noble joint venture and 1.0 billion cubic feet related to the Antero sale. The decrease in Marcellus average sales price was the result of the decline in general market prices. These decreases were offset, in part, by various gas swap transactions that matured in the year ended December 31, 2011. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These hedges represented approximately 10.6 billion cubic feet of our produced Marcellus gas sales volumes for the year ended December 31, 2011 at an average price of $4.64 per thousand cubic feet. For the year ended December 31, 2010, these financial hedges represented 1.6 billion cubic feet at an average price of $5.05 per thousand cubic feet. At December 31, 2011 and 2010, there were 110 and 52 gross Marcellus Shale wells in production, respectively.
Marcellus lifting costs were $16 million for the year ended December 31, 2011 compared to $5 million for the year ended December 31, 2010. Lifting costs per unit increased $0.10 per thousand cubic feet sold primarily due to increased expenses for well clean out and tubing replacement services performed to improve production.
Marcellus gathering costs were $15 million for the year ended December 31, 2011 compared to $10 million for the year ended December 31, 2010. Average gathering costs decreased $0.45 per unit primarily due to the 16.5 billion cubic feet of additional volumes sold.
General and direct administrative costs for the Marcellus gas segment were $17 million for the year ended December 31, 2011 compared to $8 million for the year ended December 31, 2010. General and direct administrative costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The total general and direct administrative costs increases which were discussed in the CBM segment and higher volumes of Marcellus gas sold contributed to the increase in the Marcellus gas segment. General and direct administrative costs were $0.64 per thousand cubic feet sold for the year ended December 31, 2011 compared to $0.73 per thousand cubic feet sold for the year ended December 31, 2010.
Depreciation, depletion and amortization costs were $35 million for the year ended December 31, 2011 compared to $20 million for the year ended December 31, 2010. There was approximately $27 million, or $1.04 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2011. There was approximately $18 million, or $1.72 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the year ended December 31, 2010. The rate was calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. There was approximately $8 million, or $0.28 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the year ended December 31, 2011. There was $2 million, or $0.18 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the year ended December 31, 2010. The increase was related to additional infrastructure and equipment placed in service after the 2010 period.
OTHER GAS SEGMENT
The other gas segment includes activity not assigned to the CBM, conventional or Marcellus gas segments. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific gas segment.
Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $12 million for the year ended December 31, 2011 and $8 million for the year ended December 31, 2010. Total costs related to these other sales were $19 million for the 2011 period and were $10 million for the 2010 period. The increase in costs in the period-to-period comparison were primarily attributable to increased general and direct administrative costs allocated to the other gas segment and increased depreciation, depletion and amortization. Higher general and direct administrative costs were attributable to the total gas increase as discussed in the CBM segment coupled with increased sales volumes. Higher depreciation, depletion and amortization was due to higher volumes produced and higher unit of production rates. A per unit analysis of the other operating costs in the Chattanooga shale is not meaningful due to the low volumes produced in the period-to-period analysis.
Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas division. Royalty interest gas sales revenue was $67 million for the year ended December 31, 2011 compared to $63 million for the year ended December 31, 2010. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.
Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $4 million for the year ended December 31, 2011 compared to $11 million for the year ended December 31, 2010.
Other income was $59 million for the year ended December 31, 2011 compared to $5 million for the year ended December 31, 2010. The $54 million increase was primarily due to a gain on the Hess transaction of $53 million, a gain on the sale of the Antero overriding royalty interest of $41 million, $8 million of additional interest income related to the notes receivable related to the Noble joint venture transaction, $5 million due to various transactions that occurred throughout both periods, none of which were individually material and $4 million due to increased earnings from equity affiliates. These improvements were partially offset by a loss on the Noble transaction of $57 million.
Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. Royalty interest gas costs were $59 million for the year ended December 31, 2011 compared to $54 million for the year ended December 31, 2010. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.
Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact of pipeline imbalances. The lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $4 million for the year ended December 31, 2011 compared to $10 million for the year ended December 31, 2010.
Exploration and other costs were $18 million for the year ended December 31, 2011 compared to $25 million for the year ended December 31, 2010. The $7 million decrease in costs is primarily related to a favorable settlement involving defective pipe which reduced expense in the 2011 period and lower dry hole and lease surrender costs in the 2011 period. Costs included in the exploration and other cost line are detailed as follows:
Other corporate expenses were $65 million for the year ended December 31, 2011 compared to $56 million for the year ended December 31, 2010. The $9 million increase in the period-to-period comparison was made up of the following items:
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Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continue to increase sales volumes.
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Contract buyout represents the cancellation of a drilling arrangement with a third party well driller.
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Bank fees were higher in the period-to-period comparison due to amending and extending the revolving credit facility
related to the gas segment. In April 2011, the facility was amended to allow $1 billion of borrowings and was extended to April 12, 2016.
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Stock-based compensation was higher in the period-to-period comparison primarily due to the increased allocation from CONSOL Energy as a result of the Dominion Acquisition as well as an increase in total CONSOL Energy stock-based compensation expense. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.
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The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2011 period, increased number of employees, and an increased allocation of expense from CONSOL Energy as the result of exceeding corporate targets.
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Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds no ownership interest and during the 2011 period de-consolidated the impact of this third party due to the cancellation of the drilling arrangement. Based on analysis, during the time CONSOL Energy guaranteed the bank loans the entity held, it was determined that CONOL Energy was the primary beneficiary. Therefore, the entity was fully consolidated and the earnings impact was fully reversed in the non-controlling interest line discussed below.
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Legal fees for the 2010 period were related to the special committee formed during the CNX Gas take-in transaction and also represent legal fees related to the shareholder litigation related to this transaction.
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Other corporate related expense remained consistent in the period-to-period comparison.
Interest expense related to the other gas segment was $10 million for the year ended December 31, 2011 compared to $7 million for the year ended December 31, 2010. Interest was incurred by the other gas segment on the CNX Gas revolving credit facility, a capital lease and debt held by a variable interest entity. The $3 million increase was primarily due to higher levels of borrowings on the revolving credit facility in the period-to-period comparison.
Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in which CONSOL Energy held no ownership interest, but was the primary beneficiary. The CONSOL Energy gas division was determined to be the primary beneficiary due to guarantees of the third party's bank debt related to their purchase of drilling rigs. The third-party entity provides drilling services primarily to the CONSOL Energy gas division. CONSOL Energy consolidates the entity and then reflects 100% of the impact as noncontrolling interest. The consolidation did not significantly impact any amounts reflected in the gas division income statement. The variance in the noncontrolling amounts reflects the third party's variance in earnings in the period-to-period comparison. In the year ended December 31, 2011, the drilling services contract was bought out. Subsequent to this transaction, the noncontrolling interest was de-consolidated.
OTHER SEGMENT ANALYSIS for the year ended December 31, 2011 compared to the year ended December 31, 2010:
The other segment includes activity from the sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $275 million for the year ended December 31, 2011 compared to a loss before income tax of $249 million for the year ended December 31, 2010. The other segment also includes total company income tax expense of $155 million for the year ended December 31, 2011 compared to $109 million for the year ended December 31, 2010.
Industrial supplies:
Total revenue from industrial supplies was $236 million for the year ended December 31, 2011 compared to $195 million for the year ended December 31, 2010. The increase was related to higher sales volumes.
Total costs related to industrial supply sales were $235 million for the year ended December 31, 2011 compared to $197 million for the year ended December 31, 2010. The increase of $38 million was primarily related to higher sales volumes and changes in last-in, first-out inventory valuations.
Transportation operations:
Total revenue from transportation operations was $120 million for the year ended December 31, 2011 compared to $114 million for the year ended December 31, 2010. The increase of $6 million was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-period comparison.
Total costs related to the transportation operations were $89 million for the year ended December 31, 2011 compared to $81 million for the year ended December 31, 2010. The increase of $8 million was related to the additional through-put tons handled by the operations and additional repairs and maintenance costs to maintain the Baltimore terminal facilities.
Miscellaneous other:
Additional other income of $6 million was recognized for the year ended December 31, 2011 compared to $17 million for the year ended December 31, 2010. The $11 million decrease was primarily due to $5 million related to the 2010 successful resolution of an outstanding tax issue with the Canadian Revenue Authority for the years 1997 through 2003 in which CONSOL Energy was entitled to interest on a tax refund, $2 million lower equity in earnings of affiliates in the current period compared to the prior year period and $4 million related to various transactions that have occurred throughout both periods, none of which were individually material.
Other corporate costs in the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges. Total other costs were $313 million for the year ended December 31, 2011 compared to $297 million for the year ended December 31, 2010. Other corporate costs increased due to the following items:
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Interest expense increased $41 million primarily due to interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition in April 2010.
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On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.
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Evaluation fees for non-core asset dispositions increased $4 million in the period-to-period comparison due to various corporate initiatives that began in the 2010 period.
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Bank fees increased $2 million in the period-to-period comparison due to the refinancing and extension of the previous $1.0 billion credit facility to $1.5 billion on April 12, 2011.
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Transaction and financing fees of $15 million were incurred in the year ended December 31, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to CONSOL Energy's oil and gas properties. Transaction and financing fees of $61 million were incurred in the year ended December 31, 2010 primarily related to the Dominion Acquisition, as well as the equity and debt issuance that raised approximately $4.6 billion.
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Various other corporate expenses were $19 million in the year ended December 31, 2011 compared to $20 million in the year ended December 31, 2010. The decrease of $1 million was due to various transactions that occurred throughout both periods, none of which were individually material.
Income Taxes:
The effective income tax rate was 19.7% for the year ended December 31, 2011 compared to 23.4% for the year ended December 31, 2010. The decrease in the effective tax rate for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was primarily attributable to various discrete transactions that occurred in both periods. The discrete transactions included an Internal Revenue Service audit settlement for years 2006 and 2007 and the corresponding impacts to the previously accrued tax positions which resulted in higher percentage depletion deductions. Discrete transactions also included the reversal of a valuation allowance for certain state net operating loss carryforwards and future temporary deductions as well as the reversal of certain uncertain tax positions. See Note 6-Income Taxes of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Results of Operations
Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009
Net Income Attributable to CONSOL Energy Shareholders
CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $347 million, or $1.60 per diluted share, for the year ended December 31, 2010. Net income attributable to CONSOL Energy shareholders was $540 million, or $2.95 per diluted share, for the year ended December 31, 2009. See below for a detailed explanation by segment of the variance incurred in the period-to-period comparison.
The total coal segment includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal segment contributed $536 million of earnings before income tax for the year ended December 31, 2010 compared to $546 million for the year ended December 31, 2009. The total coal segment sold 63.0 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates, in the year ended December 31, 2010 compared to 57.4 million tons in the year ended December 31, 2009. The average sales price and total costs per ton for all active coal operations were as follows:
The higher average sales price per ton sold reflects an additional 2.3 million tons of low volatile metallurgical coal and 2.4 million tons of high volatile metallurgical coal sold in 2010 compared to 2009. The low volatile metallurgical coal segment also had a higher average sales price in 2010 compared to 2009 reflecting the strengthening of the global steel market and steel related products. The high volatile metallurgical coal global market allowed approximately 2.4 million tons of coal to be sold as a metallurgical product at an average sales price of $72.89 per ton. This coal historically would have been sold on the thermal market where our average price for 2010 was $53.76 per ton.
Average costs per ton of coal sold have increased in the period-to-period comparison due primarily to additional labor, higher supply and maintenance costs, and increased other costs which are directly related to the higher sales prices received for tons sold. Additional labor costs per ton are related to the net addition of approximately 330 employees. The additional labor was attributed to the Shoemaker Mine resuming production in 2010 after being idled throughout 2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Additional labor was also added in order to run our mines more safely, to prepare for the expected retirement of a significant portion of our work force over the next five years, and to keep the development of the longwall panels ahead of longwall advancement. Additional supply costs were attributable to compliance with new safety regulations such as fire retardant belts, additional equipment maintenance and various changes in roof control measures. Costs directly related to the price received for coal sales have also increased. These costs include royalty expenses and various production taxes.
The total gas segment includes coalbed methane (CBM), conventional, Marcellus and other gas. The total gas segment contributed $180 million of earnings before income tax for the year ended December 31, 2010 compared to $263 million for the year ended December 31, 2009. Total gas production was 127.9 billion cubic feet for the year ended December 31, 2010 compared to 94.4 billion cubic feet for the year ended December 31, 2009.
The average sales price and total costs for all active gas operations were as follows:
Total gas segment outside sales revenues were $746 million for the year ended December 31, 2010 compared to $630 million for the year ended December 31, 2009. The increase was primarily due to the 35.5% increase in volumes sold, offset, in part, by
the 12.7% reduction in average price per thousand cubic feet sold. The decrease in average sales price is the result of various gas swap transactions that occurred throughout both periods. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 52.1 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2010 at an average price of $7.66 per thousand cubic feet. 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. Average gas sales prices excluding the impact of hedging were up slightly in the period-to-period comparison.
Total gas unit costs increased for the year ended December 31, 2010 compared to the year ended December 31, 2009 primarily due to the impact of the higher cost structure of the producing wells purchased in the Dominion Acquisition. These wells increased total operating costs by $0.78 per thousand cubic feet due to the higher maintenance costs, higher gathering and transportation costs and lower volumes produced compared to the legacy CONSOL Energy wells. Excluding the impact of these purchased wells, unit costs improved $0.32 per thousand cubic feet primarily due to the additional volumes produced. Volumes increased in the period-to-period comparison due to the on-going drilling program and the additional volumes from the wells purchased in the Dominion Acquisition.
The other segment includes industrial supplies activity, terminal and river service activity, income taxes and other business activities not assigned to the coal or gas segment.
TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:
The coal segment contributed $536 million of earnings before income tax in the year ended December 31, 2010 compared to $546 million in the year ended December 31, 2009. Variances by the individual coal segments are discussed below.
THERMAL COAL SEGMENT:
The thermal coal segment contributed $461 million to total company earnings before income tax in the year ended December 31, 2010 compared to $719 million in the year ended December 31, 2009. The thermal coal revenue and cost components on a per unit basis are as follows:
Thermal coal revenue was $3,001 million for the year ended December 31, 2010 compared to $3,122 million for the year ended December 31, 2009. The $121 million decrease was attributable to an average sales price reduction of $2.88 per ton partially offset by a 0.7 million increase in tons sold. Thermal coal average sales price is lower in the 2010 period compared to the 2009 period as a result of higher average sales price mines, such as Bailey and Enlow Fork, selling coal in the high volatile metallurgical coal market instead of the thermal coal market. This impacted the thermal coal segment as a result of leaving more tons sold from lower sales price mines. This has negatively impacted the average sales price on the thermal coal segment, although total company revenue has improved. Produced thermal inventory was 1.9 million tons at December 31, 2010 compared to 2.9 million tons at December 31, 2009. Thermal sales tons were higher in the period-to-period comparison primarily due to the Shoemaker Mine restarting production in early 2010 after being idled throughout 2009 to complete the replacement of the track haulage system. Thermal sales tons were also higher as the result of the Blacksville #2 Mine being idled for several months in 2009 in order to manage inventory levels in response to the economic crisis experienced. Blacksville #2 Mine has operated throughout 2010. These increases were offset, in part, due to selling 2.4 million tons on the high volatile metallurgical coal market at approximately $19.13 per ton higher average sales price.
Other income attributable to the thermal coal segment represents earnings from our equity affiliate that operates a thermal coal mine. The equity in earnings of affiliates is insignificant to the total segment activity.
Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income, royalties and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the thermal coal segment were $1,934 million for the year ended December 31, 2010 compared to $1,828 million for the year ended December 31, 2009. Higher operating costs in the period-to-period comparison are due to the $1.48 per ton increase in average unit costs of tons sold and 0.7 million of additional tons sold.
Higher average operating costs per unit for thermal coal tons sold are primarily related to the following items:
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Thermal coal unit costs were higher in 2010 as a result of lower cost mines, such as Bailey and Enlow Fork, selling coal in the high volatile metallurgical coal market. This impacted the thermal coal segment due to increased tons sold from higher cost mines.
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Labor costs increased due to the effects of wage increases at the union mines from the current labor contracts. The contracts call for specified hourly wage increases in each year of the contract. Labor costs also increased due to the effects of wage increases at the non-represented mines. Average employee counts also increased approximately 5% at our active mining operations. The additional employees were primarily due to the Shoemaker Mine resuming production in 2010 after being idled during 2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Additional employees were also added in order to run our mines more safely, to prepare for the expected retirement of a significant portion of our work force over the next five years, and to keep the development of the longwall panels ahead of longwall advancement.
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Health and retirement costs related to the active hourly work force increased due to higher contributions to the multiemployer 1974 pension trust that are required under the National Bituminous Coal Wage Agreement. The contribution rate increased from $4.25 per hour worked by members of the United Mine Workers Union of America
(UMWA) in the year ended December 31, 2009 to $5.00 per hour worked in the year ended December 31, 2010. Contributions to the multiemployer plan are expensed as incurred. Health and Retirement costs have also increased in the period-to-period comparison due to higher medical costs for the active hourly work force.
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Power costs increased due to higher rates charged by utility companies and increased usage in the period-to-period comparison.
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Operating costs also increased as a result of the 1.0 million ton decrease in inventory levels.
The increases in average unit costs of thermal coal sold were offset, in part, by the following:
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Reduced contract mining fees due to fewer contractors being retained to mine our reserves in the year ended December 31, 2010 compared to the 2009 period.
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Average operating costs per thermal ton sold decreased due to higher tons sold. Fixed costs are allocated over higher tons resulting in decreased unit costs.
Total CONSOL Energy expenses related to our actuarial liabilities were $287 million for the year ended December 31, 2010 compared to $243 million for the year ended December 31, 2009. The increase of $44 million was due primarily to changes in the discount rates used at the measurement date, which is December 31, and changes in assumptions which affect the amount of actuarial gains and losses amortized into earnings. See Note 15-Pension and Other Postretirement Benefits Plans and Note 16-Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail regarding total company expense.
Total provisions are made up of the expenses related to the Company's long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation, long-term disability and accretion expense on mine closing and related liabilities. With the exception of accretion expense on mine closing and related liabilities, these expenses are actuarially calculated for the company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. Provisions attributable to the thermal coal segment were $198 million for the year ended December 31, 2010 compared to $180 million for the year ended December 31, 2009. Provision costs per thermal coal ton sold increased $0.28 per ton in the period-to-period comparison due primarily to higher actuarial expenses, such as OPEB, as discussed above. The overall increase in company costs has increased the total dollars allocated to the thermal coal segment. This increase was offset, in part, by additional tons sold by the thermal coal segment.
Total Company Selling, General and Administrative Expenses were made up of the following items:
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Employee wages and related expenses have increased due to additional employees in the selling, general and administrative area primarily related to support staff retained in the Dominion Acquisition which occurred on April 30, 2010 and additional hiring to support operations. Increased employee wages and related expenses are also related to additional actuarial expenses discussed above.
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Commission expenses increased $5 million due to additional tons for which a third party was owed a commission compared to the prior year period.
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Miscellaneous expenses have increased approximately $5 million. The increase was related to an additional $2 million for advertising and promotion fees, an additional $2 million for demurrage charges and an additional $1 million for various other items, none of which were individually material.
Total administrative and other costs related to the thermal coal segment were $142 million for the year ended December 31, 2010 and $144 million for the year ended December 31, 2009. Selling, general and administrative costs, excluding selling expense, are allocated to all segments based on a combination of estimated time worked by various support groups and operating costs incurred by the individual segments. Commission expense, which is a component of selling, is charged directly to the mine incurring
the cost. Direct administrative costs are associated directly with the coal division of the business and are allocated to various mines based on a combination of estimated time worked and production. Although the total company selling, general and administrative costs have increased, as discussed above, the amount allocated to the thermal coal segment has decreased approximately $2 million. The decrease in the amount allocated to the thermal coal segment is primarily related to the high volatile metallurgical coal segment. In 2009, these tons and the associated allocation were all included in the thermal coal segment.
Depreciation, depletion and amortization costs for the thermal coal segment were $274 million for the year ended December 31, 2010 and $258 million for the year ended December 31, 2009. The increase of $16 million, or $0.22 per ton, was due to additional equipment and infrastructure placed into service after 2009, offset, in part, by additional volumes sold.
HIGH VOL METALLURGICAL COAL SEGMENT:
The high volatile metallurgical coal segment contributed $87 million to total company earnings before income tax for the year ended December 31, 2010. There was no activity in this segment in the prior year. This is a new market that was developed in 2010 and is primarily related to selling our Pittsburgh #8 coal into overseas metallurgical coal markets. This coal had historically supplied the domestic thermal coal market. The high volatile metallurgical coal revenue and cost components on a per unit basis are as follows:
The high volatile metallurgical coal segment revenue was $172 million, or an average sales price per ton of $72.89, for the year ended December 31, 2010. Strength in the metallurgical coal market allowed for the export of Northern Appalachian coal, historically sold domestically on the thermal coal market, to crossover to the metallurgical coal markets in Brazil and Asia. Total costs per ton sold of this coal were $39.11 generating a margin of $33.78 per ton sold. This margin exceeds the $8.12 per ton average margin received on thermal coal sold in 2010 which is where this coal would have been historically sold.
Other income attributable to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate mines that sell coal on the high volatile metallurgical coal market. The equity in earnings of affiliates is insignificant to the total segment activity.
LOW VOL METALLURGICAL COAL SEGMENT:
The low volatile metallurgical coal segment contributed $382 million to total company earnings before income tax for the year ended December 31, 2010 compared to $94 million for the year ended December 31, 2009. The increase was due primarily to the Buchanan Mine being idled for approximately five months of 2009. The mine was idled in 2009 in response to the economic crisis which significantly lowered the demand for low volatile metallurgical coal, primarily due to the decrease in steel demand. The Buchanan Mine has operated throughout all of 2010. The low volatile metallurgical coal revenue and cost components on a per unit basis are as follows:
Average sales price for low volatile metallurgical coal has increased $38.60 per ton, from the prior year, to $146.32 for the year ended December 31, 2010. The increase of 35.8% was mainly due to the strengthening of the global market for steel and steel related products when compared to 2009.
Total costs per ton sold of low volatile metallurgical coal were $64.24 per ton for the year ended December 31, 2010 compared to $67.12 per ton for the year ended December 31, 2009. The $2.88 per ton improvement was related to operating the Buchanan Mine for all of 2010 versus seven months of 2009. The additional tonnage sold in 2010 has reduced the average per unit costs.
OTHER COAL SEGMENT:
The Other Coal segment had a loss before income tax of $394 million for the year ended December 31, 2010 compared to a loss before income tax of $267 million for the year ended December 31, 2009. The Other Coal segment includes purchased coal activities, idled mine activities as well as various other activities assigned to the coal segment but not allocated to each individual mine.
Other Coal segment produced coal sales revenue was $12 million for the year ended December 31, 2010. This revenue includes the sale of incidental tonnage recovered during the reclamation process at idled facilities. The primary focus of activity at these locations is reclaiming disturbed land in accordance with permit requirements after final mining has occurred. The tons sold from these activities are incidental to total company production and sales.
Purchased coal sales were $34 million for the year ended December 31, 2010 compared to $39 million for the year ended December 31, 2009. 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 for a fee.
Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset in freight expense. Freight revenue was $126 million in the year ended December 31, 2010 compared to $149 million for the year ended December 31, 2009. The decrease of $23 million was primarily due to lower tons being shipped on CONSOL Energy freight contracts in the period-to-period comparison.
Miscellaneous other income was $48 million for the year ended December 31, 2010 compared to $70 million for the year ended December 31, 2009. The $22 million decrease was due to the following items:
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In the year ended December 31, 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 be released from the requirements of taking delivery of previously committed tons. No such transactions were entered into in the year ended December 31, 2010.
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Gain on sales of assets attributable to the Other Coal segment were $9 million for the year ended December 31, 2010 compared to $16 million for the year ended December 31, 2009. The change was related to various transactions that occurred throughout both periods, none of which were individually material.
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Coal royalty income from third parties was $15 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009. The decrease was related to lower tons mined by third parties from our coal reserves in the period-to-period comparison.
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In the year ended December 31, 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 the losses was primarily due to the decrease in market price of coal in 2009 compared to 2008. No such transactions existed in the year ended December 31, 2010.
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Other income increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Other coal segment total costs were $614 million for the year ended December 31, 2010 compared to $525 million for the year ended December 31, 2009. The increase of $89 million was due to the following items:
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Closed and idle mine costs were $215 million for the year ended December 31, 2010 compared to $138 million for the year ended December 31, 2009. The increase of $77 million in closed and idle mine costs was primarily related to additional reclamation liabilities recognized at the Fola mining operation in West Virginia. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mine plans, the reclamation liability associated with the Fola operation increased approximately $81 million. Additional closed and idle mine costs in 2010 were also related to a $14 million charge as a result of a change in the mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine has been abandoned. These increases were offset, in part, by approximately $18 million for changes in the operational status of various other mines, between idled and operating, throughout both periods which resulted in lower idled mine costs in 2010. Shoemaker Mine was idled throughout 2009 while the track haulage system was converted to a belt haulage system. This mine was in production throughout 2010.
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Litigation expense of $25 million was recognized for the year ended December 31, 2010 related to a settlement that was reached in June 2010. The litigation was related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries.
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Cost of goods sold and other charges have increased approximately $13 million related to excess purchase price over appraised values for various land purchases that have been made throughout the year. Accounting guidance requires assets purchased to be recognized at the appraised value; synergies and related specific value to CONSOL Energy cannot be reflected as an asset. Various land deals in strategic areas for items such as refuse ponds, overland belts and various other key projects often require premiums over fair value, thus resulting in additional expense to CONSOL Energy at the time of the transaction.
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Litigation settlement expense of $11 million was recognized for the year ended December 31, 2010 related to the sale of the Jones Fork Mining Complex.
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Cost of goods sold and other charges have increased approximately $8 million due to various asset abandonments throughout the period, none of which were individually material. These abandonments primarily related to engineering work, permitting work and mapping work for miscellaneous projects that are no longer being pursued by the Company.
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Purchased coal 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. These costs were $40 million for the year ended December 31, 2010 compared to $46 million for the year ended December 31, 2009. The decrease of $6 million was primarily due to reduced purchased coal volumes in the period-to-period comparison.
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Litigation expense of $17 million was recognized for the year ended December 31, 2009 related to amounts accrued for the settlement of the Levisa Action and the Pobst/Combs Action. This litigation related to depositing water in mine voids which a subsidiary of CONSOL Energy leased.
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Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight expense is offset in freight revenue. Freight expense was $126 million in the year ended December 31, 2010 compared to $149 million for the year ended December 31, 2009. The decrease of $23 million was primarily due to fewer tons shipped on CONSOL Energy freight contracts in the period-to-period comparison.
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Other costs have increased $1 million primarily due to various contingent liabilities related to potential legal settlements as well as various other transactions that have occurred throughout both periods, none of which are individually material.
TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:
The gas segment contributed $180 million to earnings before income tax for the year ended December 31, 2010 compared to $263 million for the year ended December 31, 2009. Variances by the individual gas segments are discussed below.
COALBED METHANE (CBM) GAS SEGMENT:
The CBM segment contributed $248 million to the total company earnings before income tax for the year ended December 31, 2010 compared to $304 million for the year ended December 31, 2009. The CBM segment revenue and cost components on a per unit basis were as follows:
CBM sales revenues were $573 million for the year ended December 31, 2010 compared to $597 million for the year ended December 31, 2009. The decrease was primarily due to the 8.7% reduction in average price per thousand cubic feet sold, offset, in part, by the 5.2% increase in volumes sold. The decrease in CBM average sales price was the result of various gas swap transactions at a lower average price as compared to the prior year. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 50.5 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2010 at an average price of $7.73 per thousand cubic feet. These financial hedges represented approximately 51.6 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. Average gas sales prices excluding the impact of hedging were $4.47 per thousand cubic feet in 2010 compared to $4.13 per thousand cubic feet in 2009. CBM sales volumes increased 4.5 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. We had 3,945 net CBM Wells at December 31, 2010 compared to 3,688 net CBM wells at December 31, 2009. Also, 2009 CBM volumes were lower by approximately 1.2 billion cubic feet of deferrals related to the idling of the Buchanan Mine for approximately five months during 2009.
Total costs for the CBM gas segment were $325 million for the year ended December 31, 2010 compared to $293 million for the year ended December 31, 2009. The $32 million increase in total costs in the period-to-period comparison reflects the 5.0% increase in average unit costs and the 5.2% increase in sales volumes.
CBM lifting costs were $50 million for the year ended December 31, 2010 compared to $49 million for the year ended December 31, 2009. Average CBM lifting costs per unit were $0.54 per thousand cubic feet for 2010 compared to $0.57 per thousand cubic feet for 2009. The improvement in average CBM lifting costs per unit was due to lower salt water disposal costs attributable to recycling the water produced from our wells to be used in hydraulic fracturing of new wells. Previously, fees were incurred to dispose of the salt water produced from our wells. Unit costs were also improved due to higher volumes of CBM gas sold in the period-to-period comparison resulting in fixed costs being spread over additional volumes, lowering the average per unit costs. These improvements were offset, in part, by higher severance taxes. Higher severance taxes were the result of average market price increases, excluding the impact of our hedging program. Severance taxes were also higher as a result of the Buchanan County, Virginia severance tax settlement which changed the deductions allowed in the calculation of severance tax due when the price of gas falls between certain ranges.
CBM Gathering costs were $97 million for the year ended December 31, 2010 compared to $88 million for the year ended December 31, 2009. Average CBM gathering cost were $1.06 per thousand cubic feet sold for the year ended December 31, 2010 compared to $1.01 per thousand cubic feet sold for the year ended December 31, 2009. Higher average unit costs were related to higher power costs attributable to utility rate increases in the period-to-period comparison as well as increased usage. Higher average unit costs were also attributable to additional in-transit costs related to additional capacity of firm transportation being purchased after 2009 to assure delivery of additional volumes being produced. These cost increases were offset, in part, by the 5.2% increase in volumes sold.
General and direct administrative costs attributable to the Total Gas segment have increased $26 million to $93 million for the year ended December 31, 2010 compared to $67 million for the year ended December 31, 2009. The increase was attributable to additional staffing and additional corporate service charges from CONSOL Energy. With the Dominion Acquisition, which closed on April 30, 2010, the majority of the operational support personnel were retained. Total Company general administrative costs have also increased, as explained previously, which resulted in additional charges being allocated to all segments.
General and direct administrative costs attributable to the CBM gas segment were $65 million for the year ended December 31, 2010 compared to $62 million for the year ended December 31, 2009. General and direct administrative expenses attributable to the Total Gas segment are allocated to each individual gas segment based on a combination of production and employee counts. Although Total Gas general and direct administrative costs have increased $26 million, as discussed above, the percentage allocated to the CBM segment is lower, on a unit basis, as the result of CBM production volumes to total gas volumes produced being lower primarily due to the Dominion Acquisition, which closed on April 30, 2010.
Depreciation, depletion and amortization attributable to the CBM segment was $113 million for the year ended December 31, 2010 compared to $94 million for the year ended December 31, 2009. There was approximately $87 million, or $0.98 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2010. The unit-of-production portion of depreciation, depletion and amortization was $71 million, or $0.82 per unit-of-production in the year ended December 31, 2009. The CBM unit-of-production rate used to calculate depreciation in the current year is generally calculated using the net book value of assets divided by either proved or proved developed reserves at the previous year end. The in-field drilling program and certain assets acquired in the Dominion Acquisition caused the rate to increase. There was approximately $26 million, or $0.27 per thousand cubic feet of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2010. The straight-line component was $23 million, or $0.26 per thousand cubic feet for the year ended December 31, 2009. The increase was related to additional gathering assets placed in service after 2009, offset, in part, by the increase in volumes in the period-to-period comparison.
SHALLOW OIL AND GAS SEGMENT:
The shallow oil and gas segment had a loss before income tax of $4 million for the year ended December 31, 2010 compared to a loss before income tax of $2 million for the year ended December 31, 2009. The shallow oil and gas segment revenue and cost components on a per unit basis are as follows:
Shallow Oil and Gas segment sales revenues were $116 million for the year ended December 31, 2010 compared to $8 million for the year ended December 31, 2009. Shallow Oil and Gas sales volumes increased 23.0 billion cubic feet for the year ended December 31, 2010 primarily due to the Dominion Acquisition, which closed on April 30, 2010. Approximately 95% of the acquired producing wells were shallow oil and gas type wells. There were 8,016 net Shallow Oil and Gas wells at December 2010 compared to 195 net Shallow Oil and Gas wells at December 31, 2009. No Shallow Oil and Gas gas volumes were hedged in 2010 or 2009.
Total costs for the Shallow Oil and Gas segment were $120 million for the year ended December 31, 2010 compared to $10 million for the year ended December 31, 2009. The increase of $110 million is attributable to additional volumes sold in the period-to-period comparison, offset, in part, by lower average unit costs sold. Shallow Oil and Gas average unit costs have decreased due to the significant increase in volumes related to production from wells acquired in the Dominion Acquisition, which closed on
April 30, 2010. A detailed analysis of cost categories is not meaningful due to the significant change in this segment related to the Dominion Acquisition and will therefore not be presented. General and direct administrative costs attributable to the Total Gas segment are allocated to each individual gas segment based on a combination of production and employee counts. Shallow Oil and Gas volumes are higher as a percent of total gas produced volumes in the period-to-period comparison and therefore, additional general and direct administrative costs have been allocated to the Shallow Oil and Gas gas segment in 2010.
MARCELLUS SEGMENT:
The Marcellus segment contributed $6 million to the total company earnings before income tax for the year ended December 31, 2010 compared to $4 million for the year ended December 31, 2009. The Marcellus segment revenue and cost components on a per unit basis are as follows:
The increase in Marcellus average sales price was the result of an improvement in general market prices and various gas swap transactions that occurred in the year ended December 31, 2010. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 1.6 billion cubic feet of our produced Marcellus gas sales volumes for the year ended December 31, 2010 at an average price of $5.05 per thousand cubic feet. There were no gas swap transactions for the Marcellus segment that occurred for the year ended December 31, 2009. The increase in sales volumes was primarily due to additional wells coming on-line from our on-going drilling program. At December 31, 2010 there were 52 Marcellus Shale wells in production including 17 wells acquired in the Dominion Acquisition, which closed on April 30, 2010. At December 31, 2009 there were 22 Marcellus Shale wells in production.
Total costs for the Marcellus segment were $43 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009. The increase was primarily due to the additional sales volumes and higher average unit costs.
Marcellus lifting costs were $5 million for the year ended December 31, 2010 compared to $1 million for the year ended December 31, 2009. Average Marcellus lifting costs were $0.50 per thousand cubic feet in 2010 compared to $0.12 per thousand cubic feet in 2009. The increase in average lifting costs per unit sold was due to increased road repairs and other maintenance expense primarily related to the additional number of wells drilled in the current period. Salt water disposal fees were also higher in the period-to-period comparison due to the higher volume of water produced from additional wells. These increases in costs were offset, in part, by the additional volume of Marcellus gas sold in the period-to-period comparison.
Marcellus gathering costs were $10 million for the year ended December 31, 2010 compared to $5 million for the year ended December 31, 2009. Average gathering cost per unit sold was $0.99 per thousand cubic feet for the year ended December 31, 2010 compared to $1.12 per thousand cubic feet for the year ended December 31, 2009. Lower average gathering cost per unit was primarily attributable to the 108.0% increase in volumes sold. This improvement was offset, in part, by higher power and security costs. Higher power costs were related to higher rates being charged by utility companies in the period-to-period comparison. Higher security costs were related to additional security needs at various Marcellus gathering stations.
General and direct administrative costs attributable to the Marcellus gas segment were $8 million for the year ended December 31, 2010 compared to $4 million for the year ended December 31, 2009. Average general and direct administrative costs on a per unit sold basis were $0.73 per thousand cubic feet for the year ended December 31, 2010 compared to $0.74 per thousand cubic feet for the year ended December 31, 2009. General and direct administrative costs attributable to the Total Gas segment are allocated to each individual gas segment based on a combination of production and employee counts. The total general and direct administrative cost increases, as discussed previously, were offset, in part, by higher volumes of gas produced from
Marcellus wells.
Depreciation, depletion and amortization attributable to the Marcellus segment was $20 million for the year ended December 31, 2010 compared to $7 million for the year ended December 31, 2009. There was approximately $18 million, or $1.72 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2010. The unit-of-production portion of depreciation, depletion and amortization was $6 million, or $1.27 per unit-of-production in the year ended December 31, 2009. The Marcellus unit-of-production rate used to calculate depreciation in the current year is generally calculated using the net book value of assets divided by either proved or proved developed reserves at the previous year end. The investment in drilling activities increased in higher proportion than the related gas reserves in the current period, which resulted in a higher per unit rate. There was approximately $2 million, or $0.18 per thousand cubic feet of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2010. The straight-line component was $1 million, or $0.20 per thousand cubic feet for the year ended December 31, 2009. The increase was related to additional gathering assets placed in service after 2009, offset, in part, by the increase in volumes in the period-to-period comparison.
OTHER GAS SEGMENT:
The Other gas segment includes activity not assigned to CBM, Conventional or Marcellus gas segments. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific gas segment. The other gas segment had a loss before income tax of $70 million for the year ended December 31, 2010 compared to a loss before income tax of $43 million for the year ended December 31, 2009.
Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $8 million for the year ended December 31, 2010 compared to $4 million for the year ended December 31, 2009. There was 1.4 billion cubic feet sold from this area for the year ended December 31, 2010 compared to 0.8 billion cubic feet for the year ended December 31, 2009. Total costs related to these other sales were $10 million for the year ended December 31, 2010 compared to $5 million for the year ended December 31, 2009. The increase in costs in the period-to-period comparison was primarily due to higher depreciation, depletion and amortization attributable to the additional 0.6 billion cubic feet of gas produced and higher unit-of-production rates. The higher units-of-production rates were related to a higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. A per unit analysis of the other operating costs in Chattanooga is not meaningful due to the low volumes produced in the period-to-period analysis.
Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales revenues were $63 million for the year ended December 31, 2010 compared to $41 million for the year ended December 31, 2009.
Purchased gas sales volumes represent volumes of gas we sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $11 million for the year ended December 31, 2010 compared to $7 million for the year ended December 31, 2009.
Other income was consistent at $5 million for the years ended December 31, 2010 and 2009.
Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. The changes in market prices, contractual differences among leases, and the mix of average
and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales costs were $54 million for the year ended December 31, 2010 compared to $32 million for the year ended December 31, 2009.
Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact of pipeline imbalances. The higher average cost per thousand cubic feet is due to overall price changes, contractual differences among customers and the pipeline imbalance. Purchased gas costs were $10 million for the year ended December 31, 2010 compared to $6 million for the year ended December 31, 2009.
Exploration and other costs were $25 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009. The $8 million increase was made up of the following items:
Dry hole and lease expiration costs were $7 million higher in the period-to-period comparison primarily due to lease surrenders in the current year, offset, in part, by lower dry wells drilled in the year ended December 31, 2010.
Exploration costs increased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.
Other corporate expenses were $56 million for the year ended December 31, 2010 compared to $33 million for the year ended December 31, 2009. The $23 million increase was due to the following items:
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The short-term incentive compensation program is designed to increase compensation to eligible employees when the gas segment reaches predetermined targets for safety, production and unit cost goals. Short-term incentive compensation expense is higher in 2010 due to a 13% increase in employee counts, as well as an increase in the short-term incentive compensation allocation to the gas segment. Additional employees in the total company general and administrative area were primarily related to support staff retained in the Dominion Acquisition,which closed on April 30, 2010 and additional hiring to support operations.
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Stock-based compensation is higher in the period-to-period comparison primarily due to the conversion of the CNX Gas performance share units to CONSOL Energy restricted stock units in the year ended December 31, 2009. The conversion resulted in a reduction of approximately $4 million of expense in 2009. Additional expense was also related to stock-based compensation allocated from CONSOL Energy to the gas segment in 2010. These increases were offset, in part, by the non-vested CNX Gas stock options being terminated in relation to the CNX Gas take-in transaction. The expense previously recognized for these options was reversed on the gas segment. All stock-based compensation is now allocated from CONSOL Energy.
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Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds no ownership interest, but guarantees bank loans the entity holds related to its purchases of drilling rigs. CONSOL Energy is also the main customer of the third party, and based on analysis is the primary beneficiary. Therefore, the entity is fully consolidated and then the impact is fully reversed in the noncontrolling interest line discussed below.
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Banks fees are higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment.
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Financing and acquisition fees are related to legal expenses for the special committee, formed during the CNX Gas take-in transaction, and are primarily related to the shareholder litigation.
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The year ended December 31, 2009 includes $3 million of expense related to a contract buyout with a driller in order to mitigate idle rig charges in certain areas where drilling was not expected to increase in the near term.
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Other corporate expense increased $2 million in the year-to-year comparison primarily due to unused firm transportation charges not being allocated to the operating gas segments and various other transactions that occurred throughout both periods, none of which were individually material.
Interest expense was $7 million for the year ended December 31, 2010 compared to $8 million for the year ended December 31, 2009. Interest is incurred by the gas segment on the gas segment revolving credit facility, a capital lease and debt held by a variable interest entity. No significant changes in these components occurred in the period-to-period comparison.
Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in which the CONSOL Energy gas segment holds no ownership interest, but is the primary beneficiary. The CONSOL Energy gas segment has been determined to be the primary beneficiary due to guarantees of the third party's bank debt related to their purchase of drilling rigs. The third party entity provides drilling services primarily to the CONSOL Energy gas segment. CONSOL Energy consolidates the entity and then reflects 100% of the impact as noncontrolling interest. The consolidation does not significantly impact any amounts reflected in the gas segment income statement. The variance in the noncontrolling interest amounts reflects the third party's variance in earnings in the period-to-period comparison.
OTHER SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:
The other segment includes activity from sales of industrial supplies, transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $249 million for the year ended December 31, 2010 compared to a loss of $22 million for the year ended December 31, 2009. The other segment also includes total company income tax expense of $109 million for the year ended December 31, 2010 and $221 million for the year ended December 31, 2009.
Industrial Supplies:
Total revenues from industrial supply operations were $195 million for the year ended December 31, 2010 compared to $196 million for the year ended December 31, 2009.
Total costs related to industrial supply sales were $197 million for the year ended December 31, 2010 compared to $190 million for the year ended December 31, 2009. The $7 million increase in expense is primarily due to changes in last-in-first-out valuations.
Transportation operations:
Total revenue from transportation operations was $114 million for the year ended December 31, 2010 compared to $84 million for the year ended December 31, 2009. The $30 million increase was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-period comparison.
Total costs related to transportation operations were $81 million for the year ended December 31, 2010 compared to $70 million for the year ended December 31, 2009. The $11 million increase was primarily related to the additional through-put tons at the Baltimore terminal in the period-to-period comparison.
Miscellaneous Other:
Other income was $17 million for the year ended December 31, 2010 compared to $22 million for the year ended December 31, 2009. The $5 million decrease was attributable to $6 million of Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the Company's previous headquarters in 2009. This was offset by $1 million related to various transactions that occurred throughout both periods, none of which were individually material.
Other corporate costs include interest cost, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $297 million for the year ended December 31, 2010 and $64 million for the year ended December 31, 2009. Other corporate costs increased $233 million due to the following:
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Interest expense of $198 million was incurred in the year ended December 31, 2010 compared to $24 million in the year ended December 31, 2009. The increase of $174 million was primarily attributable to the additional interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition, which closed on April 30, 2010.
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Financing and acquisition fees of $62 million were incurred in the year ended December 31, 2010 primarily related to the equity and debt issuance that raised approximately $4.6 billion dollars. These fees also include costs related to
extending and refinancing the CONSOL Energy revolving credit facility, the Dominion Acquisition and the purchase of the CNX Gas noncontrolling interest.
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Bank fees of $16 million were incurred in the year ended December 31, 2010 compared to $5 million in the year ended December 31, 2009. The increase of $11 million was primarily related to the refinanced revolving credit facility.
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Fees related to the disposition of non-core assets of $3 million were incurred in the year ended December 31, 2010.
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Various other corporate expenses were $21 million in the year ended December 31, 2010 compared to $18 million in the year ended December 31, 2009. The increase of $3 million was due to various transactions that occurred throughout both periods, none of which were individually material.
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In the year ended December 31, 2010, there was $3 million of reduced expense related to an adjustment to assumptions used in the 2009 cease use of the Company's previous headquarter liability. The year ended December 31, 2009 included $13 million of expense related to the cease use of the facility. These transactions resulted in a $16 million improvement in the period-to-period comparison.
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Severance payments of $4 million were incurred in the year ended December 31, 2009 related to various layoffs that were necessary due to the economic downturn that occurred.
Income Taxes:
The effective income tax rate was 23.4% for the year ended December 31, 2010 compared to 28.1% for the year ended December 31, 2009. The effective tax rate is sensitive 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. The mix of pre-tax income by state may also impact the overall effective tax rate. The pre-tax income mix by state has changed in the period-to-period comparison due to the Dominion Acquisition. See Note 6-Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional explanation of the effective tax rate change in the period-to-period comparison.
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. See Note 1-Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. 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.
Business Combinations
At acquisition, CONSOL Energy allocates the cost of a business acquisition to the specific tangible and intangible assets acquired and liabilities assumed based upon their relative fair values. Significant judgments and estimates are often made to determine these allocated values, and may include the use of appraisals, consideration of market quotes for similar transactions, employment of discounted cash flow techniques or consideration of other information CONSOL Energy believes relevant. The finalization of the purchase price allocation will typically take a number of months to complete, and if final values are materially different from initially recorded amounts, adjustments are recorded. Any excess of the cost of a business acquisition over the fair values of the net assets and liabilities acquired is recorded as goodwill which is not amortized to expense. Recorded goodwill of a reporting unit is required to be tested for impairment on an annual basis, and between annual testing
dates if events or circumstances change that would more likely than not reduce the fair value of a reporting unit below its net book value.
Subsequent to the finalization of the purchase price allocation, any adjustments to the recorded values of acquired assets and liabilities would be reflected in the consolidated statement of operations. Once final, it is not permitted to revise the allocation of the original purchase price, even if subsequent events or circumstances prove the original judgments and estimates to be incorrect. In addition, long-lived assets like property and equipment, amortizable intangibles and goodwill may be deemed to be impaired in the future resulting in the recognition of an impairment loss. The assumptions and judgments made when recording business combinations will have an impact on reported results of operations for many years into the future.
Other Post Employment Benefits (OPEB)
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 participants. 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 miners represented by the United Mine Workers of America (UMWA), hired after January 1, 2007, will not be eligible to receive retiree health benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked through December 31, 2013, increasing to $1.50 per hour worked effective January 1, 2014 through December 31, 2016.
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. Expected trends in future health care cost assumptions were adjusted from prior year to reflect recent experience and future expectations. The initial expected trend in health care costs at this year's measurement date of 6.85% with an ultimate trend rate of 4.50% reached in 2026. The initial expected trend rate at last year's measurement date was 8.47% with an ultimate trend rate of 4.50% reached in 2023. A 1.0% decrease in the health care trend rate would decrease interest and service cost for 2011 by approximately $20.9 million. A 1.0% increase in the health care trend rate would increase the interest and service cost by approximately $24.9 million. The discount rate is determined each year at the measurement date. The discount rate is determined 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, 2011. The appropriate discount rate was then selected from resulting discounted cash flows. For the years ended December 31, 2011 and 2010, the discount rate used to calculate the period end liability and the following year's expense was 4.51% and 5.33%, respectively. A 0.25% increase in the discount rate would have decreased 2011 net periodic postretirement benefit costs by approximately $4.7 million. A 0.25% decrease in the discount rate would have increased 2011 net periodic postretirement benefit costs by approximately $5.5 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, 2011 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, 2011, 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, 2011 Other Postretirement Benefit liability was approximately 7% less than previously expected based on our trend assumption. 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 recorded 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, 2011 financial statements was $3.2 billion. For the year ended December 31, 2011, we paid approximately $156.8 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, 2011. CONSOL Energy does not expect to contribute to the other postretirement plan in 2012. 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. The Supplemental Retirement Plan was frozen effective December 31, 2011 for certain employees and was replaced prospectively with the CONSOL Energy Defined Contribution Restoration Plan.
In March of 2009, the CNX Gas defined benefit retirement plan was merged into the CONSOL Energy's non-contributory defined benefit retirement plan. At the time, the change did not impact the benefits for employees of CNX Gas. However, during 2010 an amendment was adopted to recognize past service at CNX Gas to current employees of CNX Gas who opted out of the plan for additional company contributions into their defined contribution plan and extend coverage to employees previously not eligible to participate in this 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, 2011, compensation increases are assumed to range from 3% to 6% depending on age and job classification. The discount rate is determined each year at the measurement date. The discount rate is determined 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, 2011. The appropriate equivalent discount rate was then selected for the resulting discounted pension cash flows. For the years ended December 31, 2011 and 2010, the discount rate used to calculate the period end liability and the following year's expense was 4.50% and 5.30%, respectively. A 0.25% increase in the discount rate would have decreased the 2011 net periodic pension cost by $1.9 million. A 0.25% decrease in the discount rate would have increased the 2011 net periodic pension cost by $2.0 million. Deferred gains and losses are primarily due to historical changes in the discount rate and earnings on assets differing from expectations. At December 31, 2011 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, 2011 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, 2011 consisted of 60% equity securities and 40% debt securities.
The estimated liability recognized in the December 31, 2011 financial statements was $274.8 million. For the year ended December 31, 2011, we contributed approximately $72.2 million to defined benefit retirement plans other than multi-employer plans trust and to other pension benefits. Our obligations with respect to these liabilities are partially funded at December 31, 2011. CONSOL Energy intends 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 determined 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, 2011. The appropriate equivalent discount rate was then selected from the resulting discounted workers' compensation cash flows. For the years ended December 31, 2011 and 2010, the discount rate used to calculate the period end liability and the following year's expense was 4.40% and 5.13%, respectively. A 0.25% increase in the discount rate would have decreased the 2011 workers compensation expense cost by $0.7 million. A 0.25% decrease in the discount rate would have increased the 2011 workers compensation expense by $0.7 million. Deferred gains and losses are primarily due to historical changes in the discount rates, several years of 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 service of active employees that are eligible to file a future workers' compensation claim. At December 31, 2011, the average remaining service period is approximately 9 years. The estimated liability recognized in the financial statements at December 31, 2011 was approximately $174.1 million. CONSOL Energy's policy has been to provide for workers' compensation benefits from operating cash flow. For the year ended December 31, 2011, we made payments for workers' compensation benefits and other related fees of approximately $32.9 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2011.
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 determined 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, 2011. The appropriate equivalent discount rate was then selected from the resulting discounted coal workers' pneumoconiosis cash flows. For the years ended December 31, 2011 and 2010, the discount rate used to calculate the period end liability and the following year's expense was 4.46% and 5.21%, respectively. A 0.25% increase in the discount rate would have increased 2011 coal workers' pneumoconiosis benefit by $0.6 million. A 0.25% decrease in the discount rate would have decreased 2011 coal workers' pneumoconiosis benefit by $0.6 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 assumptions originally reflected. The estimated liability recognized in the financial statements at December 31, 2011 was $183.6 million. For the year ended December 31, 2011, we paid coal workers' pneumoconiosis benefits of approximately $11.1 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2011.
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 $650.1 million at December 31, 2011. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, 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, 2011, CONSOL Energy has deferred tax assets in excess of deferred tax liabilities of approximately $648.8 million. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary.
Deferred tax valuation allowances decreased $21.7 million in the year ended December 31, 2011 primarily due to the release of previously recognized valuation allowances related to certain Pennsylvania net operating loss carry forwards and future temporary deductions. Valuation allowances on these net operating loss carry forwards and future temporary deductions were released during the year due to positive evidence outweighing negative evidence indicating that these benefits will be utilized in future years. CONSOL Energy continues to report a deferred tax asset of approximately $35.0 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 2018 to 2030. A valuation allowance of $6.0 million continues to be recognized 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 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 $30.9 million at December 31, 2011.
Stock-Based Compensation
As of December 31, 2011, we have issued four types of share based payment awards: options, restricted stock units, performance stock options 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,
•
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
•
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, 2011, $36.6 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.66 years. See Note 18-"Stock-based Compensation" 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-Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for further discussion.
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 or development 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
CONSOL Energy 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. 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 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, CONSOL Energy 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 each year. 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 its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. On April 12, 2011, CONSOL Energy amended and extended its $1.5 billion Senior Secured Credit Agreement through April 12, 2016. The previous facility was set to expire on May 7, 2014. The amendment provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $1.5 billion for borrowings and letters of credit. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. 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 2.50 to 1.00, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 5.80 to 1.00 at December 31, 2011. The facility includes a maximum leverage ratio covenant of no more than 4.75 to 1.00 through March 2013, and no more than 4.50 to 1.00 thereafter, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CONSOL Energy and certain subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and specific letters of credit, less cash on hand, of CONSOL Energy and certain of its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 2.15 to 1.00 at December 31, 2011. The facility also includes a senior secured leverage ratio covenant of no more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio covenant is calculated as the ratio of secured debt to EBITDA. Secured debt is defined as the outstanding borrowings and letters of credit on the revolving credit facility. The senior secured leverage ratio was 0.19 to 1.00 at December 31, 2011. Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another company and amend, modify or restate, in any material way, the senior unsecured notes. At December 31, 2011, the facility had no outstanding borrowings and $266 million of letters of credit outstanding, leaving $1.2 billion 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.
CONSOL Energy also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, up to $200 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. 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 based on commercial paper rates plus a charge for administrative services paid to financial institutions. At December 31, 2011, eligible accounts receivable totaled approximately $193 million and there were no borrowings or letters of credit outstanding against the facility.
On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% Notes due March 1, 2012 in accordance with the terms of the indenture governing the Notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. CONSOL Energy's loss on extinguishment of debt was $16 million, which primarily represents the interest that would have been paid on these notes if held to maturity.
On April 12, 2011, CNX Gas entered into a $1.0 billion Senior Secured Credit Agreement which extends until April 12, 2016. It replaced the $700 million senior secured credit facility which was set to expire on May 6, 2014. The replacement facility provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1.0 billion for borrowings and letters of credit. CNX Gas can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. An amendment to the credit agreement was approved by the lenders and became effective December 14, 2011. The amendment allows unlimited investments in joint ventures for the development and operation of gas gathering systems and provides for $600 million of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE Gathering Company, a joint venture with Noble Energy to provide Marcellus gathering capability, are unrestricted under this amendment. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interest coverage ratio was 34.18 to 1.00 at December 31, 2011. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured
quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CNX Gas and its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, of CNX Gas and its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, gains and losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.00 to 1.00 at December 31, 2011. Covenants in the facility limit our ability to dispose of assets, make investments, pay dividends and merge with another company. At December 31, 2011, the facility had no amounts drawn and $70 million of letters of credit outstanding, leaving $930 million of unused capacity.
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, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact our collection of trade receivables. As a result, CONSOL Energy constantly monitors the creditworthiness of our customers. We believe that our current group of customers are financially 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 its working capital requirements, to service its debt obligations, to fund planned capital expenditures or to 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 hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $251 million at December 31, 2011. The ineffective portion of these contracts was insignificant to earnings in the year ended December 31, 2011. No issues related to our hedge agreements have been encountered to date.
CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance that additional capital resources, including debt and equity 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 in the period-to-period comparison primarily due to the following items:
•
Operating cash flow increased $274 million in 2011 due to higher net income attributable to CONSOL Energy shareholders in the period-to-period comparison. The 2011 net income included an approximately $75 million reduction due to the abandonment of Mine 84 which is discussed further in Note 10-Property, Plant and Equipment, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K. This reduction did not have a corresponding reduction to cash flows from operating activities because it was primarily related to the write-down of assets remaining at Mine 84 at the time of the abandonment, not cash obligations.
•
Operating cash flows increased due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years, none of which were individually material.
Net cash used in investing activities changed in the period-to-period comparison primarily due to the following items:
•
On April 30, 2010, CONSOL Energy paid $3.470 billion for the Dominion Acquisition. See Note 2-Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details.
•
On May 28, 2010, CONSOL Energy paid $991 million to acquire the shares of CNX Gas common stock and vested stock options which it did not previously own.
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On September 30, 2011, CONSOL Energy received net proceeds of $485 million related to the Noble transaction, net proceeds of $190 million related to the Antero transaction, and net proceeds of $54 million related to the Hess transaction. See Note 2-Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details.
•
On September 30, 2011, CONSOL Energy received a $67 million cash distribution from CONE Gathering LLC. See Note 2-Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details.
•
Total capital expenditures increased $228 million to $1.38 billion in the year ended December 31, 2011 compared to $1.15 billion in the year ended December 31, 2010. Capital expenditures for the gas segment increased $242 million due to the additional Marcellus Shale drilling in the period-to-period comparison. Capital expenditures for coal and other activities decreased $14 million in the period-to-period comparison. Face extension projects at various locations were lower by $87 million as a result of the majority of these projects being completed during the 2010 period, $13 million was incurred in the 2010 period as a result of a longwall shield lease buyout at Enlow Fork, and the 2011 period was lower by approximately $32 million related to the Buchanan Reverse Osmosis (RO) system which was primarily completed before January 1, 2011 and an approximate $42 million decrease in 2011 related to various other equipment expenditures throughout both periods. These reductions in coal and other capital were offset, in part by an approximate $122 million increase in expenditures related primarily to the ongoing development of the BMX Mine which is scheduled to begin production in early 2014, and a $38 million increase in 2011 related to the construction of the Northern West Virginia RO system.
Net cash (used in) provided by financing activities changed in the period-to-period comparison primarily due to the following items:
•
Proceeds of $2.75 billion were received on April 1, 2010 in connection with the issuance of $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020.
•
In 2010, proceeds of $1.83 billion were received in connection with the issuance of 44.3 million shares of common stock which was completed on March 31, 2010.
•
In 2011, CONSOL Energy repaid $200 million of borrowings under the accounts receivable securitization facility. In 2010, CONSOL Energy received proceeds of $150 million under this facility.
•
In 2011, CONSOL Energy paid $266 million, including a make-whole provision, to redeem the 7.875% notes that were due in March 2012.
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In 2011, CONSOL Energy paid $15 million related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020, and 6.375% Senior Notes due 2021. See Note 10-Long-Term Debt, in the Notes to the Audited Consolidated Financial Statements included Item 8 of this Form 10-K for additional details.
•
In 2011, CONSOL Energy paid outstanding borrowings of $155 million under the revolving credit facility. In 2010, CONSOL Energy paid $260 million under this facility.
•
Dividends of $96 million were paid in 2011 compared to $86 million in 2010. The increase was due to the 44.3 million additional shares issued on March 31, 2010 and also due to the increase of the regular annual dividend by 25%, or $0.10 per share, to $0.50 per share on October 27, 2011.
•
In 2011, proceeds of $250 million were received in connection with the issuance of $250 million of 6.375% senior
unsecured notes due in March 2021.
•
In 2011, CNX Gas, a wholly-owned subsidiary, paid outstanding borrowings of $129 million under its revolving credit facility compared to receiving $71 million in 2010.
The following is a summary of our significant contractual obligations at December 31, 2011 (in thousands):
_________________________
(a)
Long-term liabilities-employee related include other post-employment benefits, work-related injuries and illnesses. 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 2012 contributions are expected to approximate $110 million.
(b)
Other long-term liabilities include mine reclamation and closure and other long-term liability costs.
(c)
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, 2011, CONSOL Energy had total long-term debt of $3.198 billion outstanding, including the current portion of long-term debt of $21 million. This long-term debt consisted of:
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An aggregate principal amount of $1.5 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
•
An aggregate principal amount of $1.25 billion of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
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An aggregate principal amount of $250 million of 6.375% notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.
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An aggregate principal amount of $103 million of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 5.75% per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year.
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$31 million in advance royalty commitments with an average interest rate of 6.73% per annum.
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An aggregate principal amount of $64 million of capital leases with a weighted average interest rate of 6.46% per annum.
At December 31, 2011, CONSOL Energy also had no outstanding borrowings and had approximately $266 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.
At December 31, 2011, CONSOL Energy had no outstanding borrowings under the accounts receivable securitization facility.
At December 31, 2011, CNX Gas, a wholly owned subsidiary, had no outstanding borrowings and approximately $70 million of letters of credit outstanding under its $1.0 billion secured revolving credit facility.
Total Equity and Dividends
CONSOL Energy had total equity of $3.6 billion at December 31, 2011 and $2.9 billion at December 31, 2010. Total equity increased primarily due to net income attributable to CONSOL Energy shareholders, changes in the fair value of cash flow hedges and the amortization of stock-based compensation awards. These increases were offset, in part, by the declaration of dividends and adjustments to actuarial liabilities. See the Consolidated Statements of Stockholders' Equity in Item 8 of this Form 10-K for additional details.
Dividend information for the current year to date were as follows:
On October 27, 2011, CONSOL Energy's Board of Directors increased the regular annual dividend by 25%, or $0.10 per share, to $0.50 per share, effective immediately.
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 in excess of an annual rate of $0.40 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 2.15 to 1.00 and our availability was approximately $1.2 billion at December 31, 2011. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the year ended December 31, 2011.
Off-Balance Sheet Transactions
CONSOL Energy does not maintain 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 Audited 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, 2011. The various multi-employer benefit plans are discussed in Note 17-Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements 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, performance and various other items which are not reflected on the balance sheet at December 31, 2011. Management believes these items will expire without being funded. See Note 24-Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details of the various financial guarantees that have been issued by CONSOL Energy.
Recent Accounting Pronouncements
In December 2011, the Financial Accounting Standards Board issued an update to the Comprehensive Income Topic of the Accounting Standards Codification intended to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. This update allows entities to continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before Update 2011-05. All other requirements included within Update 2011-05 are not affected and entities must report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. The effective date of this update is for fiscal years, and interim periods within those years, beginning after December 15, 2011. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements as these updates have an impact on presentation only.
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 commodity 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, 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 our risk assessment procedures and internal controls, mitigates our exposure to material risks. However, the use of derivative instruments without other risk assessment procedures could materially affect CONSOL Energy's results of operations depending on 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-Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CONSOL Energy Inc. and Subsidiaries
We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits 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 audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CONSOL Energy Inc. and Subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), CONSOL Energy Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2011, 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 10, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 10, 2012
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 financial statements.
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
The accompanying notes are an integral part of these 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 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 financial statements.
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
The accompanying notes are an integral part of these financial statements.
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 or the Company) 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. 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. Investments in oil and gas producing entities are accounted for under the proportionate consolidation method. The accounts of variable interest entities, where CONSOL Energy is the primary beneficiary, are included in the Consolidated Financial Statements. 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 business combinations, other postretirement benefits, coal workers' pneumoconiosis, workers' compensation, salary retirement benefits, stock-based compensation, asset retirement obligations, 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. There were no material financing receivables with a contractual maturity greater than one year.
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 coal and gas operations.
Property, Plant and Equipment:
Property, plant and equipment is recorded at cost upon acquisition. 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.
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 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.
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, or at a minimum once a year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates.
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 as gain or loss in other income.
Gas well activity is accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory or development 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, or at a minimum once a year; those revisions are accounted for prospectively as changes in accounting estimates.
Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:
Costs to obtain coal lands are capitalized based on the cost 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 effect from changes in estimates is disclosed in the period the change occurs.
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 seven 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. There was no impairment expense recognized for the year ended December 31, 2011. Impairment expense of $1,813 and $4,211 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2010 and 2009, respectively, for the impairment of sales contract assets previously acquired.
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 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 do not 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.
Restricted Cash:
Restricted cash includes a $20,291 deposit into escrow as security to perfect CONSOL Energy's appeal to the Pennsylvania Environmental Hearing Board under the applicable statute related to the Ryerson dam litigation (See Note 24-Commitments and Contingent Liabilities for additional details.) Restricted cash also includes a $1,857 deposit into escrow for maintenance of a leased office building. If the monies are unutilized at the end of the lease term then they will be returned to CONSOL Energy.
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.
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 Costs:
CONSOL Energy accrues for mine closing costs, reclamation 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 Cost of Goods Sold and Other Operating Charges on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gas wells, which includes treatment of water and the reclamation of land upon exhaustion of coal and gas reserves.
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. These plans are accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB Accounting Standards Codification. The cost of these retiree benefits are recognized over the employees' service period. CONSOL Energy uses actuarial methods and assumptions in the valuation of defined benefit obligations and the determination of expense. Differences between actual and expected results or changes in the value of obligations and plan assets are recognized through Other Comprehensive Income.
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 and research and development, revenue is recognized generally as the service is provided to the customer.
CONSOL Energy 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.
CONSOL Energy 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.
CONSOL Energy purchases gas produced by third parties at market prices less a fee. The gas purchased from third party producers is then resold 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 CONSOL Energy from the third party producer.
Royalty Interest Gas Sales represent the revenues related to the portion of production belonging to royalty interest owners sold by CONSOL Energy.
Freight Revenue and Expense:
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.
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.
Issuance of Common Stock:
On March 31, 2010, CONSOL Energy issued 44,275,000 shares of common stock, which generated net proceeds of $1,828,862 to fund, in part, the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition). The acquisition transaction closed on April 30, 2010. See Note 2-Acquisitions and Dispositions for further discussion of the Dominion Acquisition.
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. There were no cash expenditures under the repurchase program between January 1, 2009 and 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. Information regarding remaining treasury shares held by CONSOL Energy is disclosed in the Consolidated Balance Sheets.
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 award's vesting term. See Note 18-Stock Based Compensation for further discussion.
Earnings per Share:
Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly 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 performance 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 and performance share options were exercised, that outstanding restricted and performance share 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. CONSOL Energy includes the impact of pro forma 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 share-based awards that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive:
Shares of common stock outstanding were as follows:
_________________
(1) See Note 18-Stock-Based Compensation for additional information.
(2) See Issuance of Common Stock in Note 1 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 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:
CONSOL Energy accounts for its business acquisitions under the acquisition 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.
Recent Accounting Pronouncements:
In December 2011, the Financial Accounting Standards Board issued an update to the Comprehensive Income Topic of the Accounting Standards Codification intended to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. This update allows entities to continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before Update 2011-05. All other requirements included within Update 2011-05 are not affected and entities must report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. The effective date of this update is for fiscal years, and interim periods within those years, beginning after December 15, 2011. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements as these updates have an impact on presentation only.
Subsequent Events:
We have evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.
NOTE 2-ACQUISITIONS AND DISPOSITIONS:
On October 21, 2011, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed a sale to Hess Ohio Developments, LLC (Hess) of 50% of its nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54,254, which are net of $5,719 transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $534,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. The net gain on the transaction was $53,095 and was recognized in the Consolidated Statements of Income as Other Income.
On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certain Marcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. Cash proceeds of $485,464 were received related to this transaction, which are net of $34,998 transaction fees. Additionally, a note receivable has been recognized related to the two additional cash payments to be received on the first and a second anniversary of the transaction closing date. The discounted notes receivable of $311,754 and $296,344 have been recorded in Accounts and Notes Receivables-Notes Receivable and Other Assets-Notes Receivable, respectively. Subsequent to the transaction, an additional receivable of $16,703 and a payable of $980 were recorded for closing adjustments and have been included in Accounts and Notes Receivable - Other and Accounts Payable, respectively. The net loss on the transaction was $64,142 and was recognized in the Consolidated Statements of Income as Other Income. As part of the transaction, CNX Gas also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $2,100,000 with certain restrictions. These restrictions include the suspension of carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMBtu) for three consecutive months. The carry will remain suspended until average natural gas prices are above $4.00/MMBtu for three consecutive months. Restrictions also include a $400,000 annual maximum on Noble's carried cost obligation.
The following unaudited pro forma combined financial statements are based on CONSOL Energy's historical consolidated financial statements and adjusted to give effect to the September 30, 2011 sale of a 50% interest in certain Marcellus Shale assets. The unaudited pro forma results for the periods presented below are prepared as if the transaction occurred as of January 1, 2010 and do not include material, non-recurring charges.
The pro forma results are not necessarily indicative of what actually would have occurred if the transaction had been completed as of January 1, 2010, nor are they necessarily indicative of future consolidated results.
On September 30 2011, CNX Gas Company and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CNX Gas Company's 50% ownership interest in CONE is accounted for under the equity method of accounting. CNX Gas contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $119,740 and Noble contributed cash of approximately $67,545. CONE made a cash distribution to CNX Gas in the amount of $67,545. The cash proceeds have been recorded as cash inflows of $59,870 and $7,675 in Distributions from Equity Affiliates and Proceeds from the Sale of Assets, respectively, on the Consolidated Statements of Cash Flow. The gain on the transaction was $7,161 and was recognized in the Consolidated Statements of Income as Other Income.
On September 21, 2011 CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in approximately 116 thousand net acres of Marcellus Shale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for $193,000. The net gain of $41,057 is included in Other Income in the Consolidated Statements of Income.
In December 2010, CONSOL Energy completed a sale-leaseback of longwall shields for the McElroy Mine. Cash proceeds from the sale were $33,383, 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 September 2010, CONSOL Energy completed a sale-leaseback of longwall shields for the Enlow Fork Mine. Cash proceeds from the sale were $14,551, 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 June 2010, CONSOL Energy paid Yukon Pocahontas Coal Company $30,000 cash to acquire certain coal reserves and $20,000 cash in advanced royalty payments recoupable against future production. Both payments were made per a settlement agreement in regards to the depositing of untreated water from the Buchanan Mine, a mine operated by one of our subsidiaries, into the void spaces of the nearby mines of one of our other subsidiaries, Island Creek Coal Company.
On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas Corporation (CNX Gas) outstanding common stock for a cash payment of $966,811 pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary of CONSOL Energy (CNX Gas Acquisition). All of the shares of CNX Gas that were not already owned by CONSOL Energy were acquired at a price of $38.25 per share. CONSOL Energy previously owned approximately 83.3% of the approximately 151 million shares of CNX Gas common stock outstanding. An additional $24,223 cash payment was made to cancel previously vested but unexercised CNX Gas stock options. CONSOL Energy financed the acquisition of CNX Gas shares by means of internally generated funds, borrowings under its credit facilities and proceeds from its offering of common stock.
On April 30, 2010, CONSOL Energy completed the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition) for a cash payment of $3,470,212 which was principally allocated to oil & gas properties, wells and well-related equipment. The acquisition, which was accounted for under the acquisition method of accounting, included approximately 1 trillion cubic feet equivalents (Tcfe) of net proved reserves and 1.46 million net acres of oil and gas rights within the Appalachian Basin. Included in the acreage holdings were approximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia. Dominion is a producer and transporter of natural gas as well as a provider of electricity and related services. The acquisition enhanced CONSOL Energy’s position in the strategic Marcellus Shale fairway by increasing its development assets.
The results of operations of the acquired entities are included in CONSOL Energy's Consolidated Statements of Income as of May 1, 2010. Net revenues and net income (loss) resulting from the Dominion Acquisition that were included in CONSOL Energy's operating results were $133,850 and $(5,364), respectively, for the year ended December 31, 2010.
The unaudited pro forma results for the year ended December 31, 2010, assuming the acquisition had occurred at January 1, 2010, are presented below. Pro forma adjustments include estimated operating results, transaction and financing fees incurred, additional interest related to the $2.75 billion of senior unsecured notes and 44,275,000 shares of common stock issued in connection with the transaction.
The pro forma results are not necessarily indicative of what actually would have occurred if the Dominion Acquisition had been completed as of January 1, 2010, nor are they necessarily indicative of future consolidated results.
CONSOL Energy incurred $65,363 of acquisition-related costs as a direct result of the Dominion Acquisition and CNX Gas Acquisition for the year ended December 31, 2010. These expenses have been included within Transaction and Financing Fees on the Consolidated Statements of Income for the year ended December 31, 2010.
In March 2010, CONSOL Energy completed the sale of the Jones Fork Mining Complex as part of a litigation settlement with Kentucky Fuel Corporation. No cash proceeds were received and $10,482 of litigation settlement expense was recorded in Cost of Goods Sold and Other Operating Charges. The loss recorded was net of $8,700 related to the fair value of estimated amounts to be collected related to an overriding royalty on future mineable and merchantable coal extracted and sold from the property.
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 FASB Accounting Standards Codification related to the Company's previous headquarters. This liability was recorded in Other Liabilities on the Consolidated Balance Sheets at December 31, 2009. Total expense related to this transaction was $12,500 which was recognized in Cost of Goods Sold and Other Operating Charges. This amount included the fair value of the remaining lease payments of $10,974 as well as the removal of a related asset of $1,526. Additionally, $5,832 was recognized in Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the premises that occurred in 2005. In the year ended December 31, 2010, the cease use expense was reduced by $2,999 as a result of a change in estimated cash flows.
In August 2009, CONSOL Energy completed the lease assignment of CNX Gas' previous headquarters. Total expense related to this transaction for the year ended December 31, 2010 was $1,500, which was recognized in Cost of Goods Sold and Other Operating Charges.
In August 2009, CONSOL Energy completed a sale-leaseback 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.
In July 2009, CONSOL Energy, through a subsidiary, leased approximately 20 thousand acres having Marcellus Shale potential from NiSource Energy Ventures, LLC, a subsidiary of 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 Statements of Cash Flow. The purchase price for the transaction was principally allocated to gas properties and related development.
In February 2009, CONSOL Energy completed a sale-leaseback 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.
NOTE 3-OTHER INCOME:
NOTE 4-INTEREST EXPENSE:
Interest on other payables for the year ended December 31, 2011 includes a reversal of interest expense of $3,096 related to uncertain tax positions. See Note 6-Income Taxes for further discussion.
NOTE 5-TAXES OTHER THAN INCOME:
NOTE 6-INCOME TAXES:
Income taxes (benefits) provided on earnings consisted of:
The components of the net deferred tax assets are as follows:
**Valuation allowance of ($41,016) has been allocated to long-term deferred tax assets for 2011. Valuation allowances of ($778) and ($61,890) have been allocated between current and long-term deferred tax assets respectively for 2010.
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. At December 31, 2011 and 2010, positive evidence considered included financial and tax earnings generated over the past three years for certain subsidiaries, 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 by certain subsidiaries in prior periods and the inability to achieve forecasted results at certain subsidiaries for those periods. CONSOL Energy continues to report, on an after federal tax basis, a deferred tax asset related to state operating losses of $57,669 with a related valuation allowance of $34,980 at December 31, 2011. The deferred tax asset related to state operating losses, on an after federal tax adjusted basis, was $58,428 with a related valuation allowance of $39,744 at December 31, 2010. A review of positive and negative evidence regarding these state operating benefits concluded that a valuation allowance for various CONSOL Energy subsidiaries was warranted. The net operating losses expire at various times between 2012 and 2030.
The deferred tax assets attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial and tax losses was also reviewed for positive and negative evidence regarding the realization of the deferred tax assets. A valuation allowance of $6,036 and $22,924 was recognized at December 31, 2011 and 2010, respectively. Included in the valuation allowance against the future deductible temporary differences at December 31, 2011 and 2010, were $872 and $9,639 of allowances which were recognized through Other Comprehensive Income. These allowances relate to actuarial gains/losses for other postretirement, pension and long-term disability benefits that were recognized through Other Comprehensive Income. Management will continue to assess the potential for realizing deferred tax assets based upon 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.
During 2011, the deferred tax asset relating to alternative minimum tax decreased $86,760. This change was due to: $55,251 estimated utilization relating to 2011 activity, $25,687 utilization relating to the year 2010 accrual to return adjustment, and $5,823 utilization relating to the 2006-2007 audit settlement.
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:
If these unrecognized tax benefits were recognized, $3,891 and $16,802 respectively would have affected CONSOL Energy's effective income tax rate for the years ended December 31, 2011 and 2010, respectively.
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 2008. 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 received a refund of $4,560 in 2010 as a result of the 2009 audit settlement recorded as a tax refund receivable in 2009.
The IRS completed its audit of CONSOL Energy's income tax returns filed for 2006 and 2007. The Company concluded this examination and remitted payment of the resulting tax deficiencies to federal and state taxing authorities before December 31, 2011. CONSOL paid $6,404 and $4,361 for tax years 2006 and 2007, respectively. The IRS will commence its audit of tax years 2008 and 2009 in 2012. 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 is not expected to have a significant 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, 2011 and 2010, the Company had an accrued liability of $5,373 and $10,774 respectively, for interest related to uncertain tax positions. Interest expense related to unrecognized tax benefits was ($3,096), $2,436 and $2,409 that were recorded in the Company's Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009, respectively. Interest expense was reduced during the year ended December 31, 2011 due to the reversal of various uncertain tax liabilities primarily due to the expiration of statutes. During the year ended December 31, 2011, CONSOL Energy paid $1,633 and $673 of interest related to income tax deficiencies for tax years 2006 and 2007 with the IRS.
CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2011 and 2010, 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.
The reconciliation of changes in the asset retirement obligations at December 31, 2011 and 2010 is as follows:
For the year ended December 31, 2010, Revisions in estimated cash flows include $80,525 related to additional reclamation liabilities recognized at the Fola mining operation in West Virginia. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mine plans, the reclamation liability associated with the Fola operation was revised.
For the year ended December 31, 2011, Other includes ($6,698) for asset dispositions related to the sale of the Bishop mining operation. For the year ended December 31, 2010, Other includes ($7,400) for asset dispositions related to the sale of Jones Fork Mining Complex. See Note 2-Acquisitions and Dispositions for additional details.
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 $22,406 and $19,624 at December 31, 2011 and December 31, 2010, 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. The facility allows CONSOL Energy to receive on a revolving basis up to $200,000. The facility also allows for the issuance of letters of credit against the $200,000 capacity. At December 31, 2011, there were no letters of credit outstanding against the facility.
CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, buys and sells 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, who in turn sells these receivables 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 a short average collection cycle for such receivables, our
collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.
In accordance with the Transfers and Servicing Topic of the FASB Accounting Standards Codification, CONSOL Energy records transactions under the securitization facility as secured borrowings on the Consolidated Balance Sheets. The pledge of collateral is reported as Accounts Receivable - Securitized and the borrowings are classified as debt in Borrowings under Securitization Facility.
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 $1,986, $2,676 and $2,990 for the years ended December 31, 2011, 2010 and 2009, 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. The receivables facility expires in April 2012.
At December 31, 2011 and 2010, eligible accounts receivable totaled $192,700 and $200,000, respectively. There was subordinated retained interest of $192,700 at December 31, 2011 and there was no subordinated retained interest at December 31, 2010. There were no borrowings under the securitization facility recorded on the Consolidated Balance Sheets at December 31, 2011. Accounts Receivable - Securitization and Borrowings under Securitization Facility of $200,000 were recorded on the Consolidated Balance Sheets at December 31, 2010. Also, a $200,000 decrease, $150,000 increase and $115,000 decrease in the accounts receivable securitization facility for the years ended December 31, 2011, 2010 and 2009, respectively, are reflected in the Net Cash (Used In) Provided By Financing Activities in the Consolidated Statements of Cash Flows. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.
NOTE 10-PROPERTY, PLANT AND EQUIPMENT:
Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary; 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.
Coal reserves are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and 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 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.
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 or development wells are expensed when such wells are determined to be non-productive. Also, if an exploratory well has found sufficient quantities of reserves but the determination is subsequently made that the related project is no longer viable, the exploratory well is expensed. 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. Any material effect from changes in estimates is disclosed in the period the change occurs.
The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yet commenced or have ceased, and therefore, are not being amortized for the years ended December 31, 2011 and 2010, respectively.
As of December 31, 2011 and 2010, plant and equipment includes gross assets under capital lease of $95,995 and $88,859, respectively. For the years ended December 31, 2011 and 2010, 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, 2011 and 2010, the Gas segment also maintains a capital lease for vehicles of $8,664 and $5,919, respectively, which are included in Other gas assets. For the years ended December 31, 2011 and 2010, the All Other segment maintains capital leases for vehicles and computer equipment of $20,412 and $16,021, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $39,854 and $30,251 at December 31, 2011 and 2010, respectively. Amortization expense for capital leases is included in Depreciation, Depletion and Amortization in the Consolidated Statements of Income. See Note 14-Leases for further discussion of capital leases.
Long-Lived Asset Abandonment
In June 2011, CONSOL Energy decided to permanently close its Mine 84 mining operation located near Washington, PA. This decision was part of CONSOL Energy's ongoing effort to reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The closure decision resulted in the recognition of an abandonment expense of $115,817
for the year ended December 31, 2011. The abandonment expense resulted from the removal of the June 30, 2011 carrying value of the following Mine 84 related assets from the Consolidated Balance Sheets: Mine development - $92,136, Airshafts - $15,352, Coal equipment - $2,080, Inventories - $757, and Prepaid Expenses - $385. Additionally, the Mine 84 abandonment expense also includes the recognition of a Mine Closing expense of $5,107. The effect on net income of the Mine 84 abandonment was $75,281 of expense for the year ended December 31, 2011. The impact to basic and dilutive earnings per share was $0.33 for the year ended December 31, 2011.
Industry Participation Agreements
In 2011, CONSOL Energy entered into two significant industry participation agreements (also referred to as "joint ventures" or "JVs") that provided drilling and completion carries for our retained interests. The following table provides information about our industry participation agreements as of December 31, 2011:
NOTE 11-SHORT-TERM NOTES PAYABLE:
On April 12, 2011, CONSOL Energy amended and extended its $1,500,000 Senior Secured Credit Agreement through April 12, 2016. The previous facility was set to expire on May 7, 2014. The amendment provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $1,500,000 of borrowings and letters of credit. CONSOL Energy can request an additional $250,000 increase in the aggregate borrowing limit amount. 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 2.50 to 1.00, measured quarterly. The interest coverage ratio was 5.80 to 1.00 at December 31, 2011. The facility includes a maximum leverage ratio covenant of not more than 4.75 to 1.00, measured quarterly. The leverage ratio was 2.15 to 1.00 at December 31, 2011. The facility also includes a senior secured leverage ratio covenant of not more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio was 0.19 to 1.00 at December 31, 2011. 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, merge with another corporation and amend, modify or restate the senior unsecured notes. At December 31, 2011, the $1,500,000 facility had no borrowings outstanding and $265,673 of letters of credit outstanding, leaving $1,234,327 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2010, the $1,500,000 facility had $155,000 of borrowings outstanding and $266,656 of letters of credit outstanding, leaving $1,078,344 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 3.76% at December 31, 2010.
On April 12, 2011, CNX Gas entered into a $1,000,000 Senior Secured Credit Agreement which extends until April 12, 2016. It replaced the $700,000 Senior Secured Credit Facility which was set to expire on May 6, 2014. The replacement facility provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1,000,000 for borrowings and letters of credit. CNX Gas can request an additional $250,000 increase in the aggregate borrowing limit amount. The facility was increased to meet the asset development needs of the company. 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, pay dividends and merge with another corporation. An amendment to the credit agreement was approved by the lenders and became effective December 14, 2011. The amendment allows unlimited investments in joint ventures for the development and operation of gas gathering systems and provides for $600,000 of loans, advances, and dividends from CNX Gas to CONSOL Energy. Investments in the CONE Gathering Company (See Note 27-Related Party Transactions) are unrestricted under this amendment. The facility includes a maximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.00 to 1.00 at December 31, 2011. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 34.18 to 1.00 at December 31, 2011. At December 31, 2011, the $1,000,000 facility had no borrowings outstanding and $70,203 of letters of credit outstanding, leaving $929,797 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2010, the $700,000 facility had $129,000 of borrowings outstanding and
$70,203 of letters of credit outstanding, leaving $500,797 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 2.26% as of December 31, 2010.
NOTE 12-OTHER ACCRUED LIABILITIES:
NOTE 13-LONG-TERM DEBT:
Annual undiscounted maturities on long-term debt during the next five years are as follows:
On March 9, 2011 CONSOL Energy closed the offering of $250,000 of 6.375% senior notes which mature on March 1, 2021. The notes are guaranteed by substantially all of our existing wholly owned domestic subsidiaries.
On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250,000, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The redemption price included principal of $250,000, a make-whole premium of $15,785 and accrued interest of $2,188 for a total redemption cost of $267,973. The loss on extinguishment of debt was $16,090, which primarily represents the interest that would have been paid on these notes if held to maturity.
In August 2011, CONSOL Energy paid the remaining principal balance on the 6.10% Notes due December 2012. The early debt retirement was completed as a condition of a drilling services contract termination with a variable interest entity.
Transaction and financing fees of $14,907 were incurred during the year ended December 31, 2011 related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020 and 6.375% Senior Notes due 2021. The consents allowed an amendment of the indentures for each of those notes, clarifying that the joint venture transactions with Noble and Hess were permissible under those indentures. See Note 2-Acquisitions and Dispositions for additional information.
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, 2011, are as follows:
Rental expense under operating leases was $111,861, $94,137, and $77,960 for the years ended December 31, 2011, 2010 and 2009, 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. 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. The Supplemental Retirement Plan was frozen effective December 31, 2011 for certain employees and was replaced prospectively with the CONSOL Energy Defined Contribution Restoration Plan.
In March of 2009, the CNX Gas defined benefit retirement plan was merged into the CONSOL Energy's non-contributory defined benefit retirement plan. At the time, the change did not impact the benefits for employees of CNX Gas. However, during 2010 an amendment was adopted to recognize past service at CNX Gas to current employees of CNX Gas who opted out of the plan for additional company contributions into their defined contribution plan and extend coverage to employees previously not eligible to participate in this 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. 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 participants. 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 through December 31, 2013, increasing to $1.50 per hour worked effective January 1, 2014 through December 31, 2016.
For the year ended December 31, 2011 CONSOL Energy received proceeds of $7,973 under the Patient Protection and Affordable Care Act (PPACA) related to reimbursement from the Federal Government for retiree health spending. This amount is included as a reduction of benefit and other payments in the reconciliation of changes in benefit obligation. There is no guarantee that additional proceeds will be received under this program.
The OPEB liability reflects an increase of $11,800 and $12,300 as of December 31, 2011 and 2010, respectively, due to the PPACA reform legislation; in particular, the estimated impact of the potential excise tax beginning in 2018. A corresponding increase in Other Comprehensive Loss was also recognized. The estimated increase in the liability was calculated using the following assumptions: testing pre-Medicare and Medicare covered retirees on a combined basis; assuming individual participants have an average 2012 claim cost and future healthcare trend assumptions equal to those used in the year end valuation; assuming the 2018 tax threshold amount to increase for inflation in later years. These assumptions may change once additional guidance becomes available.
The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2011 and 2010, is as follows:
The components of net periodic benefit costs are as follows:
Amounts included in accumulated other comprehensive loss, expected to be recognized in 2012 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:
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 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 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 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 SEC. 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, 2011 and 2010 by asset category are as follows:
__________
(a)
This category includes investments in U.S. common stocks and corporate debt.
(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 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 Value 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 corporate 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 US 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.
(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.
(n)
This category invests in a U.S. long duration corporate investment grade portfolio at a 90% weight and a U.S. long treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade corporate bonds with an emphasis on reducing default risk through active management 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 Corporate Index and 10% to the Barclay's Capital Long Treasury.
There are no investments in CONSOL Energy stock held by these plans at December 31, 2011 or 2010.
There are no assets in the other postretirement benefit plans at December 31, 2011 or 2010.
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 $110 million to our pension plan trust in 2012. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2011. 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 assumptions originally reflected.
The CWP liability was remeasured as of April 1, 2010 due to new legislation enacted in the Patient Protection and Affordable Care Act (PPACA). In general, the PPACA impacts CONSOL Energy's liability in that future claims will be approved at a higher rate than has occurred in the past. The PPACA made two changes to the Federal Black Lung Benefits Act (FBLBA). First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused at his/her work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner's death. The impact of the new law increased CONSOL Energy's CWP liability by $45,700. The law change increased expense by $6,658 for the year ended December 31, 2010. In conjunction with the law change, CONSOL Energy conducted an extensive experience study regarding the rate of claim incidence. Based on historical company data and available industry data, with emphasis on recent history, certain assumptions were revised at the remeasurement date. Most notably, the expected number of claims, prior to the law change, was reduced to more appropriately reflect CONSOL Energy's historical experience. The assumption and remeasurement changes resulted in a decrease in the liability of $47,700. The assumption and remeasurement changes reduced expense by $10,576 for the year ended December 31, 2010.
The combined impact of the changes in actuarial assumptions, remeasurement and changes to the FBLBA was a net decrease of $1,232 in liability, net of $768 tax, as well as Accumulated Other Comprehensive Income based on an April 1, 2010 remeasurement date. The combined impact of these changes reduced expense by $3,918 for the year ended December 31, 2010.
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' 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 healthcare 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.
The components of the net periodic cost (credit) are as follows:
Amounts included in accumulated other comprehensive income, expected to be recognized in 2012 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:
Cash Flows:
CONSOL Energy does not intend to make contributions to the CWP or Workers' Compensation plans in 2012. 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 1974 Pension Trust:
Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan (1974 Pension Trust EIN 52-1050282/002) negotiated with the United Mine Workers of America (UMWA) and contained in the National Bituminous Coal Wage Agreement (NBCWA). The 1974 Pension Trust is overseen by a board of trustees, consisting of two union-appointed trustees and two employer-appointed trustees. The trustees' responsibilities include selection of the plan's investment policy, asset allocation, individual investment of plan assets and the administration of the plan. The benefits provided by the 1974 Pension Trust to the participating employees are determined based on age and years of service at retirement. The current 2011 NBCWA will expire on December 31, 2016 and calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The required contribution called for by the current NBCWA for the period beginning January 1, 2012 and ending December 31, 2016 is $5.50 per hour worked. For the plan year ended June 30, 2011, approximately 18% of retirees and surviving spouses receiving benefits from the 1974 Pension Trust last worked at signatory subsidiaries of CONSOL Energy.
For the plan year ended June 30, 2011, approximately 28% of contributions made to the 1974 Pension Trust came from certain signatory subsidiaries of CONSOL Energy. Total contributions made by signatory subsidiaries of CONSOL Energy to the UMWA 1974 Pension Trust were $36,209, $31,591 and $25,620, for the years ended December 31, 2011, 2010 and 2009, respectively. These multi-employer pension plan contributions are expensed as incurred. 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. CONSOL Energy expects its signatory subsidiaries to contribute approximately $36,379 to the 1974 Pension Trust in 2012. Contributions to this multi-employer pension plan could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to the 1974 Pension Trust, lower than expected returns on pension assets or other funding deficiencies. Contribution rates for the 1974 Pension Trust required beyond December 31, 2016, cannot be estimated at this time.
As of June 30, 2011, the most recent date for which information is available, the 1974 Pension Trust was underfunded. This determination was made in accordance with Employer Retirement Income Security Act of 1974 (ERISA) calculations, with a total actuarial asset value of $5,077,338 and a total actuarial accrued liability of $6,618,702, or a funded percentage of approximately 76.5%. On October 21, 2011, certain subsidiaries of CONSOL Energy received notice from the trustees of the 1974 Pension Trust stating that the plan is considered to be “seriously endangered” for the plan year beginning July 1, 2011. The Pension Protection Act (Pension Act) requires a funded percentage of 80% be maintained for this multi-employer pension plan, and if the plan is determined to have a funded percentage of less than 80% it will be deemed to be “endangered” or "seriously endangered", if the number of years to reach a projected funding deficiency equals 7 or less in addition to having a funded percentage of less than 80%, and if less than 65%, it will be deemed to be in “critical” status. The funded percentage certified by the actuary for the 1974 Pension Trust was determined to be 76.50% under the Pension Act.
Certain subsidiaries of CONSOL Energy face risks and uncertainties by participating in the 1974 Pension Trust. All assets contributed to the plan are pooled and available to provide benefits for all participants and beneficiaries. As a result, contributions made by signatory subsidiaries of CONSOL Energy benefit employees of other employers. If the 1974 Pension Trust fails to meet ERISA's minimum funding requirements or fails to develop and adopt a rehabilitation plan, a nondeductible excise tax of five percent of the accumulated funding deficiency may be imposed on an employer's contribution to this multi-employer pension plan. As a result of the 1974 Pension Trust's “seriously endangered” status, steps must be taken under the Pension Act to improve the funded status of the plan. As a result, the Pension Protection Act requires the 1974 Pension Trust to adopt a funding improvement plan no later than May 25, 2012, to improve the funded status of the plan, which may include increased contributions to the 1974 Pension Trust from employers in the future. Because the 2011 NBCWA established our signatory subsidiaries contribution obligations through December 31, 2016, our signatory subsidiaries' contributions to the 1974 Pension Trust should not increase during the term of the NBCWA as a consequence of any funding improvement plan adopted by the 1974 Pension Trust to address the plan's seriously endangered status.
Under current law governing multi-employer defined benefit plans, if certain signatory subsidiaries of CONSOL Energy voluntarily withdraw from the 1974 Pension Trust, the currently underfunded multi-employer defined benefit plan would require the withdrawing subsidiaries to make payments to the plan which would approximate the proportionate share of the multiemployer plan's unfunded vested benefit liabilities at the time of the withdrawal. The 1974 Pension Trust uses a modified “rolling five” method for calculating an employer's share of the unfunded vested benefits, or the withdrawal liability, for a plan year. An employer would be obligated to pay its pro-rata share of the unfunded vested benefits based on the ratio of hours worked by the employer's employees during the previous five plan years for which contributions were due compared to the number of hours worked by all the employees of the employers from which contributions were due. The 1974 Pension Trust's unfunded vested benefits at June 30, 2011, the end of the latest plan year, were $4,288,252. CONSOL Energy's signatory subsidiaries' percentage of hours worked
compared during the previous five plan years to the total hours worked by all plan participants during the same period was estimated to be approximately 28%. These factors result in an estimated withdrawal liability of approximately $1,196,946.
UMWA Benefit Trusts:
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 $13,609, $19,904, and $22,646 for the years ended December 31, 2011, 2010 and 2009, respectively. Based on available information at December 31, 2011, CONSOL Energy's obligation for the Act is estimated at approximately $183,651.
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 2011 labor agreement are $0.50 per hour worked by UMWA represented employees for the year ended December 31, 2011. Contributions to the trust under the 2007 agreement were $1.42 per hour worked by UMWA represented employees for the year ended December 31, 2010, comprised of a $0.50 per hour worked under the labor agreement and $0.92 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 were $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 2006 Act. Total contributions were $3,824, $9,086 and $8,968 for the years ended December 31, 2011, 2010 and 2009, 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 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 $67,349, $67,768, and $61,734 for years ended December 31, 2011, 2010 and 2009, respectively. The 2011, 2010 and 2009 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, 2011, approximately 32% 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-Stock Based Compensation for further discussion of CONSOL Energy's equity incentive plans.
On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas outstanding common stock pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary. As a result of this acquisition, CNX Gas no longer has its own independent equity incentive plan. Prior to the acquisition, the CNX Gas equity incentive plan consisted 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 could be granted under CNX Gas' plan was 2,500,000. CNX Gas stock-based compensation expense resulted in pre-tax expense of $2,766, $2,043 and $6,311 for the years ended December 31, 2011, 2010 and 2009, respectively.
Long Term Incentive Compensation:
Prior to the acquisition of the minority interest in CNX Gas, 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 at the program vesting date. 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. A credit to expense of approximately $1,434 was recognized during 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. As a result of the completed exchange offer there are no outstanding performance share units.
Investment Plan:
CONSOL Energy has an investment plan available to all domestic, non-represented employees. Effective January 1, 2006, the company contribution was 6% of base pay for all non-represented employees except for those employees of Fairmont Supply Company whose contribution remains a match of 50% of the first 12% of base pay contributed by the employee. Total payments and costs were $30,532, $27,221, and $24,353 for the years ended December 31, 2011, 2010 and 2009, respectively.
Long-Term Disability:
CONSOL Energy has a Long-Term Disability Plan available to all eligible 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 $35,638 and $36,233 at December 31, 2011 and 2010, 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 to 23,800,000. At December 31, 2011, 3,137,524 shares are available for all awards. The Plan, as amended, provides 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 stock options and by 1.44 for each share issued in settlement of Performance Share Units (PSUs) or Restricted Stock Units (RSUs). No award of stock options may be exercised under the plan after the tenth anniversary of the effective date of the award.
CONSOL Energy recognizes stock-based 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 $46,076, $45,550 and $32,723 for the years ended December 31, 2011, 2010 and 2009, respectively. The related deferred tax benefit totaled $17,325, $17,473 and $12,490, for the years ended December 31, 2011, 2010 and 2009, 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 uses 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 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, 2011, 2010 and 2009 were $9,913, $10,361 and $9,950, 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 4,965,695 stock options outstanding under the Equity Incentive plan. Additionally, there are 291,612 fully vested employee stock options outstanding which vested under 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 78,203 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, 2011, and 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, 2011. 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, 2011, 2010 and 2009 was $18,049, $10,722 and $4,502, respectively.
Cash received from option exercises for the years ended December 31, 2011, 2010 and 2009 was $9,033, $5,993 and $2,547, respectively. The excess tax benefit realized for the tax deduction from option exercises totaled $8,281, $15,365, and $3,270, for the years ended December 31, 2011, 2010 and 2009, 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 is recognized over the vesting period of the units. The total fair value of the restricted stock units granted during the years ended December 31, 2011, 2010 and 2009 was $24,882, $28,762 and $42,720, respectively. The total fair value of shares vested during the years ended December 31, 2011, 2010 and 2009 was $16,496, $22,244 and $18,092, respectively. The following represents the unvested restricted stock units and their 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 is 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, 2011, 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, 2011, 2010 and 2009 was $11,648, $8,882 and $5,684. 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:
Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance stock options. These awards entitle the holder to receive shares of common stock subject to the achievement of certain performance goals. Compensation expense is recognized over the vesting period of the units. At December 31, 2011, achievement of the performance goals is believed to be probable. The total fair value of performance share options vested during the year ended December 31, 2011 was $3,299. The following represents the unvested performance options and their corresponding fair value (based upon the closing share price) at the date of grant:
As of December 31, 2011, $36,643 of total unrecognized compensation cost related to all unvested stock-based awards is expected to be recognized over a weighted-average period of 1.66 years. When stock options are exercised and restricted and performance stock 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-Significant Accounting Policies.
NOTE 19-ACCUMULATED OTHER COMPREHENSIVE LOSS:
Components of accumulated other comprehensive loss consist of the following:
The cash flow hedges that CONSOL Energy holds are disclosed in Note 23-Derivative Instruments. The adjustments for Actuarially Determined Liabilities are disclosed in Note 15-Pension and Other Postretirement Benefit Plans and Note-16 Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation.
NOTE 20-SUPPLEMENTAL CASH FLOW INFORMATION:
The following are non-cash transactions that impact the investing and financing activities of CONSOL Energy. For non-cash transactions that relate to acquisitions and dispositions, refer to Note 2.
CONSOL Energy holds capital leases on automobiles for company use. The amortization of the capital asset results in a non-cash transaction as the asset has not yet been purchased. The capital lease obligations result in non-cash transactions of $7,389, $7,158, and $3,375 for the years ended December 31, 2011, 2010, and 2009, respectively.
In 2009, CONSOL Energy sold an aircraft hangar in exchange for a note receivable of $989. Also during 2009, CONSOL Energy completed a land sale to Noble Co. - B&N Coal, Inc. in exchange for a note receivable in the amount of $800.
The following table shows cash paid during the year for:
NOTE 21-CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:
CONSOL Energy markets thermal 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.
Concentration of credit risk is summarized below:
Accounts receivable from thermal coal utilities and steel and coke producers include amounts sold under the accounts receivable securitization facility. See Note 9-Accounts Receivable Securitization for further discussion. 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 year ended December 31, 2011 sales to our largest coal customer, Xcoal Energy Resources, comprised over 10% of our revenues. Coal sales to Xcoal Energy Resources were $662,109 during 2011. For the years ended December 31, 2010 and 2009, no customer comprised over 10% of our revenues.
NOTE 22-FAIR VALUE OF FINANCIAL INSTRUMENTS:
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 value for 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-term maturity of these instruments.
Restricted cash: The carrying amount reported in the balance sheets for restricted cash approximates its fair value due to the short-term 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.
Borrowings under Securitization Facility: The carrying amount reported in the balance sheets for borrowings under the securitization facility approximates its fair value due to the short-term maturity of these instruments.
Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are 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. 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 period. 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.
CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.
CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas revenues. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodity. As of December 31, 2011, the total notional amount of the Company’s outstanding natural gas swap contracts was 164.1 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2015 and meet the criteria for cash flow hedge accounting. During the next twelve months, $93,298 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings, as a result of the settlement of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.
The fair value at December 31, 2011 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $251,277. The total asset is comprised of $153,376 and $97,901 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets.
The fair value at December 31, 2010 of CONSOL Energy’s derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $79,960 and a liability of $3,720. The total asset is comprised of $52,022 and $27,938 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $3,191 and $529 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.
The effect of derivative instruments in cash flow hedging relationships on the Consolidated Statements of Income and the Consolidated Statements of Stockholders' Equity are as follows:
NOTE 24-COMMITMENTS AND CONTINGENGENT 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. We accrue the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. Our current estimated accruals 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. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CONSOL Energy; however, such amount cannot be reasonably estimated. The amount claimed against CONSOL Energy is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case. The maximum aggregate amount claimed in those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimated exceeds the aggregate amounts accrued for all lawsuits and claims by approximately $1,387,000.
The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized.
American Electric Corp: On August 8, 2011, the United States Environmental Protection Agency, Region IV, sent Consolidation Coal Company a General Notice and Offer to Negotiate regarding the Ellis Road/American Electric Corp. Superfund Site in Jacksonville, Florida. The General Notice was sent to approximately 180 former customers of American Electric Corp. CONSOL Energy has confirmed that it did business with American Electric Corp. in 1983-84. The General Notice indicates that the Environmental Protection Agency (EPA) has determined that polychlorinated biphenyls (PCBs) and other contaminants in the soils and sediments at and near the site require a removal action to address those areas. The Offer to Negotiate invites the potentially responsible parties (PRPs) to enter into an Administrative Settlement Agreement and Order on Consent to provide for conducting the removal action under the EPA oversight and to reimburse the EPA for its past costs, in the amount of $384 and for its future costs. CONSOL Energy has responded to the EPA indicating its willingness to participate in such negotiations, and CONSOL Energy is participating in the formation of a group of potentially responsible parties to consider conducting the removal action. The actual scope of the work has yet to be determined, but the current estimate of the total costs of the removal action is in the range of $2,000 to $5,000, with CONSOL Energy's share of such costs at approximately 8%. CONSOL Energy has established an initial accrual based on its percentage share of the costs at the high end of the range. The liability is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.
Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under the Superfund program established by the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), with respect to the Ward Transformer site in Wake County, North Carolina. 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. 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 $65,000. The current estimated cost of the most likely remediation plan for the additional areas discovered is approximately $11,000. Also, in September 2008, the EPA notified CONSOL Energy and sixty 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. CONSOL Energy recognized $3,502 and $3,422 of expense in Cost of Goods Sold and Other charges in the years ended December 31, 2010 and 2009, respectively. The amounts recognized in Cost of Goods Sold and Other Charges for the year ended December 31, 2011 were immaterial. CONSOL Energy also
funded $250, $1,209 and $5,500 in the years ended December 31, 2011, 2010 and 2009, respectively, to an independent trust established for this remediation. As of December 31, 2011, 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 incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy's portion of recoveries from settled claims is $4,491. Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at December 31, 2011 is $3,468.
Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 7,500 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, New Jersey, Texas 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. Based on over 15 years of experience with this litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestos cases have not been material.
The following lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly no accrual has been recognized.
Ryerson Dam Litigation: In 2008, the Pennsylvania Department of Conservation and Natural Resources (the 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 at its Bailey Mine caused cracks and seepage damage to the Ryerson Park Dam. The Commonwealth subsequently altered the dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resource damages totaling $58,000. On February 16, 2010, the Department of Environmental Protection (DEP) issued its interim report, concluding that the alleged damage was subsidence related. The DEP estimated the cost of repair to be approximately $20,000. The Company has appealed the DEP's findings to the Pennsylvania Environmental Hearing Board (PEHB), which will consider the case de novo, meaning without regard to the DEP's decision, as to any finding of causation of damage and/or the amount of damages. Either party may appeal the decision of the PEHB to the Pennsylvania Commonwealth Court, and then, as may be allowed, to the Pennsylvania Supreme Court. A hearing on the merits of the case will not occur until sometime in the spring or summer of 2013. As to the underlying claim, CONSOL Energy 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. For that reason, we have not accrued a liability for this claim; however, if CONSOL Energy is ultimately found to be liable for damages to the dam, we believe the range of loss would be between $9,000 and $30,000.
South Carolina Gas & Electric Company Arbitration: 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, both wholly owned subsidiaries of CONSOL Energy. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. CONSOL Energy 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 April 30, 2012. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them. For that reason, we have not accrued a liability for this claim. If the named CONSOL Energy defendants prevail, the range of recovery would be between $5,100 and $6,800. If liability is ultimately imposed on the named CONSOL Energy defendants, we believe the range of loss would be between $16,000 and $27,000.
CNX Gas Shareholders Litigation: CONSOL Energy has been named as a defendant in five putative class actions brought by alleged shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share. The two cases filed in Pennsylvania Common Pleas Court have been stayed and the three cases filed in the Delaware Chancery Court have been consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL). All five actions generally allege that CONSOL Energy breached and/or aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders, essentially alleging that the $38.25 per share price that CONSOL Energy paid to CNX Gas shareholders in the tender offer and subsequent short-form merger was unfair. Among other things, the actions sought a permanent injunction against or rescission of the tender offer, damages, and attorneys' fees and expenses. The lawsuit will likely go to trial, possibly in 2012. CONSOL
Energy believes that these actions are without merit and intends to defend them vigorously. For that reason, we have not accrued a liability for this claim; however, if liability is ultimately imposed, based on the expert reports that have been exchanged by the parties, we believe the range of loss could be up to $221,000.
The following royalty and land right lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly, no accrual has been recognized. These claims are influenced by many factors which prevent the estimation of a range of potential loss. These factors include, but are not limited to, generalized allegations of unspecified damages (such as improper deductions), discovery having not commenced or not having been completed, unavailability of expert reports on damages and non-monetary issues are being tried. For example, in instances where a gas lease termination is sought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period. An estimate is calculated, if applicable, when sufficient information becomes available.
C. L. Ritter: On March 1, 2011, the Company was served with a complaint instituted by C. L. Ritter Lumber Company Incorporated against Consolidation Coal Company (CCC), Island Creek Coal Company, (ICCC), CNX Gas Company LLC, subsidiaries of CONSOL Energy Inc., as well as CONSOL Energy itself in the Circuit Court of Buchanan County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water from mining activities at CCC's Buchanan Mine into nearby void spaces at one of the mines of ICCC. The suit alleges damages of between $34,000 and $430,000 for alleged damage to coal and coalbed methane, as well as breach of contract damages. We have removed the case to federal court and filed a motion to dismiss, largely predicated on the statute of limitations bar. The trial judge ruled that the issue of the applicability of the statute of limitations bar can only be addressed after discovery. Three similar lawsuits were filed recently, one in the same court and two in the Circuit Court of Buchanan County, Virginia, by other plaintiffs that collectively allege damages of between $100,000 and $622,000. The Company has or intends to file motions to dismiss those suits as well. One of the three suits which claimed damages of $22,000 has been dismissed in federal court and has been appealed. CCC believes that it had, and continues to have, the right to store water in these void areas. CCC and the other named CONSOL Energy defendants 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. Consequently, we have not recognized any liability related to these actions.
Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company LLC et. al. The lawsuit alleges that the plaintiff class consists of oil and gas owners, that the Virginia Supreme Court has decided that coalbed methane (CBM) belongs to the owner of the oil and gas estate, that the Virginia Gas and Oil Act of 1990 unconstitutionally allows force pooling of CBM, that the Act unconstitutionally provides only a 1/8 royalty to CBM owners for gas produced under the force pooling orders, and that the Company only relied upon control of the coal estate in force pooling the CBM notwithstanding the Virginia Supreme Court decision holding that if only the coal estate is controlled, the CBM is not thereby controlled. The lawsuit seeks a judicial declaration of ownership of the CBM and that the entire net proceeds of CBM production (that is, the 1/8 royalty and the 7/8 of net revenues since production began) be distributed to the class members. The Magistrate Judge issued a Report and Recommendation in which she recommended that the District Judge decide that the deemed lease provision of the Gas and Oil Act is constitutional as is the 1/8 royalty, and that CNX Gas need not distribute the net proceeds to class members. The Magistrate Judge recommended against the dismissal of certain other claims, none of which are believed to have any significance The District Judge affirmed the Magistrate Judge's Recommendations in their entirety. The plaintiffs and CNX Gas have agreed to stay this litigation. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.
Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in Federal court in Virginia styled Addison v. CNX Gas Company LLC. The case involves two primary claims: (i) the plaintiff and similarly situated CNX Gas lessors identified as conflicting claimants during the force pooling process before the Virginia Gas and Oil Board are the owners of the CBM and, accordingly, the owners of the escrowed royalty payments being held by the Commonwealth of Virginia; and (ii) CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. Plaintiffs seek a declaratory judgment regarding ownership and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking), for force pooling coal owners after the Ratliff decision declared coal owners did not own the CBM; negligent breach of duties as an operator; breach of fiduciary duties; and unjust enrichment. We filed a Motion to Dismiss in this case, and the Magistrate Judge recommended dismissing some claims and allowing others to proceed. The District Judge affirmed the Magistrate Judge's Recommendations in their entirety. The plaintiffs and CNX Gas Company have agreed to stay this litigation. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.
Hall Litigation: A purported class action lawsuit was filed on December 23, 2010 styled Hall v. CONSOL Gas Company in Allegheny County Pennsylvania Common Pleas Court. The named plaintiff is Earl D. Hall. The purported class plaintiffs are all Pennsylvania oil and gas lessors to Dominion Exploration and Production Company, whose leases were acquired by CONSOL Energy. The complaint alleges more than 1,000 similarly situated lessors. The lawsuit alleges that CONSOL Energy incorrectly calculated royalties by (i) calculating line loss on the basis of allocated volumes rather than on a well-by-well basis, (ii) possibly calculating the royalty on the basis of an incorrect price, (iii) possibly taking unreasonable deductions for post-production costs and costs that were not arms-length, (iv) not paying royalties on gas lost or used before the point of sale, and (v) not paying royalties on oil production. The complaint also alleges that royalty statements were false and misleading. The complaint seeks damages, interest and an accounting on a well-by-well basis. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.
Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 captioned Earl Kennedy (and others) v. CNX Gas Company and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas Company and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas Company. The complaint, as amended, seeks injunctive relief, including removing CNX Gas Company 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. The suit also seeks a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court denied the plaintiff's summary judgment motion on that issue. The court held a bench trial on the “roof/rider” coal issue in November 2011 and briefing will take place before a decision is rendered. CNX Gas Company and CONSOL Energy believe this lawsuit to be without merit and intend to vigorously defend it. Consequently, we have not recognized any liability related to these actions.
Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas Company, Dominion Resources, and EQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease in southern West Virginia. EQT was the original lessee, but they farmed out the development of the lease to Dominion, in exchange for an overriding royalty. Dominion sold the indirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, the subsidiary that held the lease was merged into CNX Gas Company as part of an internal reorganization. Rowland alleges that (i) Dominion's sale of the subsidiary to CONSOL Energy was a change in control that required its consent under the terms of the farmout agreement and lease, and (ii) the subsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. Rowland alleges that the failure to obtain the required consent constitutes a breach of the lease and it seeks damages and a forfeiture of the lease. CONSOL Energy and CNX Gas Company have filed a motion to dismiss the complaint, arguing among other things, that Dominion's sale of the indirect subsidiary was not a change in control; that even if the sale constituted a change in control, the purchase agreement between Dominion and CONSOL Energy did not give effect to the transfer so the transfer never occurred; that the mergers did not require consent; and that Rowland did not provide timely notice of breach of the lease in accordance with its terms. Rowland is amending its complaint to include allegations that CONSOL Energy and Dominion Resources are liable for their subsidiaries' actions. We will file a motion to dismiss in response. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.
Majorsville Storage Field Declaratory Judgment: On March 3, 2011, an attorney sent a letter to CNX Gas Company regarding certain leases that CNX Gas Company obtained from Columbia Gas in Greene County, Pennsylvania involving the Majorsville Storage Field. The letter was written on behalf of three lessors alleging that the leases totaling 525 acres are invalid, and had expired by their terms. The plaintiffs' theory is that the rights of storage and production are severable under the leases. Ignoring the fact that the leases have been used for gas storage, they claim that since there has been no production or development of production, the right to produce gas expired at the end of the primary terms. On June 16, 2011 in the Court of Common Pleas of Greene County, Pennsylvania, the Company filed a declaratory judgment action, seeking to have a court confirm the validity of the leases. We believe that we will prevail in this litigation based on the language of the leases and the current status of the law. Consequently, we have not recognized any liability related to these actions.
The following lawsuit and claims include those for which a loss is remote and accordingly, no accrual has been recognized, although if a non favorable verdict were received the impact could be material.
Comer Litigation: In 2005, plaintiffs Ned Comer and others filed a purported class action lawsuit in the U.S. District Court for the Southern District of Mississippi against a number of companies in energy, fossil fuels and chemical industries, including CONSOL Energy styled, Comer, et al. v. Murphy Oil, et al. The plaintiffs, residents and owners of property along the Mississippi Gulf coast, alleged that the defendants caused the emission of greenhouse gases that contributed to global warming, which in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to destroy the plaintiffs' property. The District Court dismissed the case and the plaintiffs appealed. The Circuit Court panel reversed and the defendants sought a rehearing before the entire court. A rehearing before the entire court was granted, which had the effect of vacating the panel's reversal, but before the case could be heard on the merits, a number of judges recused themselves and there was no longer a quorum. As a result, the District Court's dismissal was effectively reinstated. The plaintiffs asked the U.S. Supreme Court to require the Circuit Court to address the merits of their appeal. On January 11, 2011, the Supreme Court denied that request. Although that should have resulted in the dismissal being a finality, the plaintiffs filed a lawsuit on May 27, 2011, in the same jurisdiction against essentially the same defendants making nearly identical allegations as in the original lawsuit. The defendants intend to seek an early dismissal of the case.
At December 31, 2011, 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 credit 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.
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. Coal and Gas financial guarantees have primarily been provided to support various sales contracts. Other guarantees have been extended to support insurance policies, legal matters, full and timely payments of mining equipment leases, and various other items necessary in the normal course of business.
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 Sheet. As of December 31, 2011, the purchase obligations for each of the next five years and beyond were as follows:
Costs related to these purchase obligations include:
NOTE 25-SEGMENT INFORMATION:
CONSOL Energy has two principal business divisions: Coal and Gas. The principal activities of the Coal division are mining, preparation and marketing of thermal coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes four reportable segments. These reportable segments are Thermal, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the year ended December 31, 2011, the Thermal aggregated segment includes the following mines: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the year ended December 31, 2011, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine. For the year ended December 31, 2011, the High Volatile Metallurgical aggregated segment includes: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, Miller Creek Complex and Robinson Run coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, as well as various other activities assigned to the Coal division but not allocated to each individual mine. The principal activity of the Gas division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Gas division includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, Shallow Oil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the Gas division but not allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities. 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.
Industry segment results for the year ended December 31, 2011 are:
(A)
Included in the Coal segment are sales of $662,109 to Xcoal Energy & Resources.
(B)
Includes equity in earnings of unconsolidated affiliates of $15,803, $4,231 and $4,629 for Coal, Gas and All Other, respectively.
(C)
Includes investments in unconsolidated equity affiliates of $34,316, $96,914 and $50,806 for Coal, Gas and All Other, respectively.
Industry segment results for the year ended December 31, 2010 are:
(D)
There were no sales to customers aggregating over 10% of total revenue in 2010.
(E)
Includes equity in earnings of unconsolidated affiliates of $13,846, $479 and $7,103 for Coal, Gas and All Other, respectively.
(F)
Includes investments in unconsolidated equity affiliates of $21,463, $23,569 and $48,477 for Coal, Gas and All Other, respectively.
(G)
Total Gas includes $3,470,212 acquisition of Dominion Exploration and Production Business.
Industry segment results for the year ended December 31, 2009 are:
(H) There were no sales to customers aggregating over 10% of total revenue in 2009.
(I) Includes equity in earnings of unconsolidated affiliates of $5,663, $636 and $9,408 for Coal, Gas and All Other, respectively.
(J) Includes investments in unconsolidated equity affiliates of $12,569, $24,590 and $46,374 for Coal, Gas and All Other, respectively.
Reconciliation of Segment Information to Consolidated Amounts:
Revenue and Other Income:
Earnings Before Income Taxes:
_________________________
(K) Excludes amounts specifically related to the gas segment.
Enterprise-Wide Disclosures:
CONSOL Energy's Revenues by geographical location:
_________________________
(L) CONSOL Energy attributes revenue to individual countries based on the location of the customer.
(M) CONSOL Energy has contractual relationships with certain U.S. based customers who distribute coal to international markets.
CONSOL Energy's Property, Plant and Equipment by geographical location are:
NOTE 26-GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:
The payment obligations under the $1,500,000, 8.000% per annum notes due April 1, 2017, the $1,250,000, 8.250% per annum notes due April 1, 2020, and the $250,000, 6.375% per annum notes due March 1, 2021 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by substantially all 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, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. 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 wholly 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.
Income Statement for the Year Ended December 31, 2011:
Balance Sheet for December 31, 2011:
Condensed Statement of Cash Flows
For the Year Ended December 31, 2011:
Income Statement for the Year Ended December 31, 2010:
Balance Sheet for December 31, 2010:
Condensed Statement of Cash Flows
For the Year Ended December 31, 2010:
Income Statement for the Year Ended December 31, 2009:
Condensed Statement of Cash Flows
For the Year Ended December 31, 2009:
NOTE 27-RELATED PARTY TRANSACTIONS
CONE Gathering LLC Related Party Transactions
During the year ended December 31, 2011, CONE Gathering LLC (CONE), a 50% owned affiliate, provided CNX Gas Company LLC (CNX Gas Company) gathering services in the ordinary course of business. Gathering services received from CONE were $4,267. In addition, CONSOL Energy and CNX Gas Company provide various administrative support functions to CONE. CONSOL Energy and CNX Gas Company are reimbursed by CONE for these support services. Services provided by CNX Gas Company were $592 for the year ended December 31, 2011. During the start-up phase of this joint-venture, CNX Gas Company also provided treasury support functions including making all required payments to vendors on behalf of CONE. Payments to vendors on behalf of CONE were $12,743 for the year ended December 31, 2011.
As of December 31, 2011, CONSOL Energy and CNX Gas had a net receivable of $8,966 due from CONE which is comprised of the following items:
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's coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2011, 742 million tons were assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2011 include 3,838 million tons of steam coal reserves, of which approximately 7 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million British thermal unit (Btu), 15 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu and an additional 78 percent has a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per million BTU. The reserves also include 621 million tons of metallurgical coal in consolidated reserves, of which approximately 64 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu and an additional 36 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.
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.
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, 2011, 2010 and 2009, we drilled 254.9, 317 and 247 net development wells, respectively. There were no net dry development wells in 2011, one net dry development well in 2010 and one net dry development well in 2009.
During the years ended December 31, 2011, 2010 and 2009, we drilled 69.5, 38 and 18 net exploratory wells, respectively.
There were two net dry exploratory wells in 2011, two net dry exploratory wells in 2010 and one net dry exploratory well in 2009.
At December 31, 2011, there were 47 net development wells in the process of being drilled.
At December 31, 2011, there were 2.5 net exploratory wells in the process of being drilled.
CONSOL Energy is committed to provide 89.8 bcf of gas under existing sales contracts or agreements over the course of the next four years. CONSOL Energy 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 Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2011, the number of producing wells, developed acreage and undeveloped acreage:
____________
(1)
Net acres include acreage attributable to our working interests of the properties. 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.
Proved Oil and Gas Reserve Quantities:
The preparation of our gas reserve estimates are completed in accordance with CONSOL Energy's 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 2011 gas reserve results were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer. The gas reserve estimates are as follows:
__________
(a)
Revisions are due to price, efficiencies in operations, and changes in the current five year plan as well as a comprehensive look into reservoir characterization and well performance.
(b)
Extensions and Discoveries are due to the drilling of proved undeveloped, probable and possible locations adhering to Security and Exchange Commission (SEC) guidelines on booking PUD locations if reliable technology can be demonstrated. The reliable technologies that were utilized include wire line open-hole log data, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized production performance from CONSOL Energy's and competitors' wells. Geophysical data includes data from CONSOL Energy's wells, published documents, and state data-sites and was used to confirm continuity of the formation.
(c)
Proved developed and proved undeveloped gas reserves are defined by 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. CONSOL Energy 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 which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.
_________
(a)
Gas equivalent reserves are expressed in billions of cubic feet equivalent (BCFE), determined using the ratio of 6 billion cubic feet of gas to 1 million barrels of oil.
_________
(a)
During 2011, various exploration and development drilling and evaluations were completed. Approximately, $134,064 of capital was spent in the year ended December 31, 2011 related to undeveloped reserves that were transferred to developed.
(b)
Included in proved undeveloped reserves at December 31, 2011 are approximately 121,003 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports the continual operation of the mine for many years past, unless there was an extreme circumstance which resulted from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.
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. During 2011, three wells were removed from the previous year-end schedule. One of these wells was connected and is now producing while two wells were determined to be dry or uneconomical to pursue and expensed.
CONSOL Energy's 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, 2011. 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 CONSOL Energy. 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. CONSOL Energy's 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 CONSOL Energy's proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.
The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:
Supplemental Quarterly Information (unaudited):
(Dollars in thousands, except per share data)
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
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 the Company’s “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 the Company’s disclosure controls and procedures are effective as of December 31, 2011 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 includes 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, 2011. 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, 2011.
The effectiveness of CONSOL Energy's internal control over financial reporting as of December 31, 2011 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 in the Company's internal controls over financial reporting 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. and Subsidiaries
We have audited CONSOL Energy Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2011, 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. and Subsidiaries' 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. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011 of CONSOL Energy Inc. and Subsidiaries and our report dated February 10, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 10, 2012
ITEM 9B.
OTHER INFORMATION
None.
PART III
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-Biographies of Directors,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITS COMMITTEES-Corporate Governance Web Page and Available Documents,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITS COMMITTEES-Audit Committee”, "BOARD OF DIRECTORS AND COMPENSATION INFORMATION - BOARD OF DIRECTORS AND ITS COMMITTEES - Membership and Meetings of the Board of Directors and its Committees," and “SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement for the annual meeting of shareholders to be held on May 1, 2012 (the “Proxy Statement”).
Executive Officers of CONSOL Energy
The following is a list of CONSOL Energy executive officers, their ages as of February 10, 2012 and their positions and offices held with CONSOL Energy.
J. Brett Harvey has been Chief Executive Officer and a Director of CONSOL Energy since January 1998. He was elected Chairman of the Board of CONSOL Energy on June 29, 2010. Mr. Harvey was the President of CONSOL Energy from January 1998 until February 23, 2011. 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 has been President of CONSOL Energy since February 23, 2011. He was Executive Vice President and Chief Operating Officer of CONSOL from January 16, 2009 until February 23, 2011. Prior to that time, Mr. DeIuliis served as Senior Vice President - Strategic Planning of CONSOL Energy from November 2004 until August 2005, 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, a position which he continues to hold.
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 Vice President, 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 and President of CNX Land Resources Inc. on September 13, 2011. 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, our principal financial and accounting officer 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 June 1, 2011, 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.
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-2011,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-UNDERSTANDING OUR DIRECTOR COMPENSATION TABLE,” and “EXECUTIVE COMPENSATION AND STOCK OPTION INFORMATION” in the Proxy Statement.
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.
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 “PROPOSAL NO. 1-ELECTION OF DIRECTORS-Determination of Director Independence” in the Proxy Statement.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference from the information under the caption “ACCOUNTANTS AND AUDIT COMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in the Proxy Statement.
PART IV
ITEM 15.
EXHIBIT INDEX
In reviewing any agreements incorporated by reference in this Form 10-K or filed with this 10-K, please remember that such agreements are included to provide information regarding their terms. They are not intended to be a source of financial, business or operational information about CONSOL Energy or any of its subsidiaries or affiliates. The representations, warranties and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof as characterizations of the actual state of facts or condition of CONSOL Energy or any of its subsidiaries or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.
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 and to the commission subsequent to the filing of this Form 10-K.
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 10th day of February, 2012.
CONSOL ENERGY INC.
By:
/S/ J. BRETT HARVEY
J. Brett Harvey
Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 10th day of February, 2012, by the following persons on behalf of the registrant in the capacities indicated:
Signature
Title
/S/ J. BRETT HARVEY
Chairman of the Board and Chief Executive Officer
J. Brett Harvey
(Principal Executive Officer)
/S/ WILLIAM J. LYONS
Chief Financial Officer and Executive Vice President
William J. Lyons
(Principal Financial Officer)
/S/ JOHN L. WHITMIRE
Vice Chairman of the Board
John L. Whitmire
/S/ PHILIP W. BAXTER
Lead Independent Director
Philip W. Baxter
/S/ JAMES E. ALTMEYER, SR.
Director
James E. Altmeyer, Sr.
/S/ WILLIAM E. DAVIS
Director
William E. Davis
/S/ RAJ K. GUPTA
Director
Raj K. Gupta
/S/ PATRICIA A. HAMMICK
Director
Patricia A. Hammick
/S/ DAVID C. HARDESTY, JR.
Director
David C. Hardesty, Jr.
/S/ JOHN T. MILLS
Director
John T. Mills
/S/ WILLIAM P. POWELL
Director
William P. Powell
/S/ JOSEPH T. WILLIAMS
Director
Joesph T. Williams
SCHEDULE II
CONSOL ENERGY INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(Dollars in thousands)