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Filed Pursuant to Rule 424(b)(5)
Registration Statement No. 333-151292

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to be Registered		Amount to be Registered(1)		Proposed Maximum Offering Price Per Share		Maximum Aggregate Offering Price(1)		Amount of Registration Fee(2)
Common Stock, par value $0.01 per share(3)		44,275,000		$42.50		$1,881,687,500		$134,165

 

(1)	Includes 5,575,000 shares of common stock that may be sold upon exercise of the underwriters’ over-allotment option.

 

(2)	Calculated in accordance with Rule 457(r) under the Securities Act of 1933 and relates to the registration statement on Form S-3 (File No. 333-151292) filed by the Registrant.

 

(3)	Each share of common stock includes a right to purchase preferred share purchase right as described in the Rights Agreement by and between the Registrant and Equiserve Trust Company, N.A., as Rights Agent, dated as of December 22, 2003, as amended.

 

PROSPECTUS    SUPPLEMENT

(To prospectus dated May 30, 2008)

38,500,000 Shares

CONSOL Energy Inc.

Common Stock

 

 

We are selling 38,500,000 shares of our common stock.

The net proceeds from this offering will be used to fund, in part, the proposed acquisition of certain assets from Dominion Resources, Inc., to fund a portion of the acquisition of shares of CNX Gas Corporation, which we do not own and for other general corporate purposes.

Our shares trade on the New York Stock Exchange under the symbol “CNX.” On March 25, 2010, the last sale price of the shares as reported on the New York Stock Exchange was $42.97 per share.

Investing in the common stock involves risks that are described in the “Risk Factors” section beginning on page S-17 of this prospectus supplement.

 

 

 

		Per Share		Total
Public offering price		$42.50		$1,636,250,000
Underwriting discount		$1.275		$49,087,500
Proceeds, before expenses, to us		$41.225		$1,587,162,500

The underwriters may also purchase up to an additional 5,775,000 shares from us, at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus supplement to cover over-allotments, if any.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement is truthful or complete. Any representation to the contrary is a criminal offense.

The shares will be ready for delivery on or about March 31, 2010.

 

 

Joint Book-Running Managers

BofA Merrill Lynch

PNC Capital Markets LLC

Scotia Capital

Stifel Nicolaus

Senior Co-Managers

 

BMO Capital Markets		Credit Agricole CIB				RBS

Co-Managers

 

UBS Investment Bank		Brean Murray, Carret & Co.		FBR Capital Markets

 

Howard Weil Incorporated		Pritchard Capital Partners, LLC

 

 

The date of this prospectus supplement is March 25, 2010.

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TABLE OF CONTENTS

Prospectus Supplement

 

		Page
About this Prospectus Supplement		S-ii
Forward-Looking Statements		S-iii
Where You Can Find More Information		S-vi
Prospectus Supplement Summary		S-1
The Offering		S-8
Summary Historical Consolidated Financial and Operating Data		S-9
Summary Unaudited Pro Forma Combined Financial Information		S-14
Risk Factors		S-17
The Acquisition and Related Financing Transactions		S-37
Use of Proceeds		S-39
Capitalization		S-40
Selected Historical Consolidated Financial Data		S-41
Common Stock Market Prices and Dividends		S-43
Unaudited Pro Forma Combined Financial Information		S-44
Description of Capital Stock		S-50
Material U.S. Federal Tax Consequences to Non-U.S. Holders		S-51
Underwriting		S-54
Legal Matters		S-59
Experts		S-59
Index to Financial Statements		F-1

Prospectus

 

		Page
About this Prospectus		1
CONSOL Energy Inc.		1
Risk Factors		2
Forward-Looking Information		15
Use of Proceeds		18
Ratio of Earnings to Fixed Charges		18
Description of Securities		19
Description of CONSOL Energy Capital Stock		19
Description of Debt Securities		23
Description of Warrants		23
Description of Purchase Contracts		23
Description of Units		24
Description of Depositary Shares		24
Forms of Securities		24
Plan of Distribution		26
Where You Can Find More Information		27
Experts		29

 

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ABOUT THIS PROSPECTUS SUPPLEMENT

This prospectus supplement supplements the accompanying prospectus. The accompanying prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or SEC, using a “shelf” registration process. Under this shelf registration process, we may offer from time to time common stock, senior or subordinated debt securities, preferred stock, warrants, purchase contracts, units or depositary shares. The accompanying prospectus provides you with a general description of these securities, and this prospectus supplement contains specific information about the terms of this offering of shares of our common stock. Both this prospectus supplement and the accompanying prospectus include important information about us, our securities and other information you should know before investing.

This prospectus supplement, or the information incorporated by reference, may add, update or change information in the accompanying prospectus. If information in this prospectus supplement, or the information incorporated by reference, is inconsistent with the accompanying prospectus, this prospectus supplement, or the information incorporated by reference, will apply and will supersede that information in the accompanying prospectus.

It is important for you to read and consider all information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus in making your investment decision. You should also read and consider the information in the documents we have referred you to under “Where You Can Find More Information” in this prospectus supplement.

When used in this prospectus supplement, unless the context requires otherwise, the terms “we,” “our,” “us,” the “Company,” and “CONSOL Energy” refer to CONSOL Energy and its subsidiaries. Unless otherwise specified, any reference to a “year” is to a fiscal year ended December 31.

 

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FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this prospectus supplement to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference herein and therein are forward-looking statements (within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference herein and therein speak only as of the date of this prospectus supplement; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

 

•

the continued weakness in global economic conditions or in any industry in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;

 

•

an extended decline in prices we receive for our coal and gas affecting our operating results and cash flows;

 

•

reliance on customers honoring existing contracts, extending existing contracts or entering into new long-term contracts for coal;

 

•

reliance on major customers;

 

•

our inability to collect payments from customers if their creditworthiness declines;

 

•

the disruption of rail, barge and other systems that deliver our coal;

 

•

a loss of our competitive position because of the competitive nature of the coal and gas industries, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;

 

•

our inability to hire qualified people to meet replacement or expansion needs;

 

•

our inability to maintain satisfactory labor relations;

 

•

coal users switching to other fuels in order to comply with various environmental standards related to coal combustion;

 

•

the inability to produce a sufficient amount of coal to fulfill our customers’ requirements which could result in our customers initiating claims against us;

 

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•

foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;

 

•

the risks inherent in coal mining being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, accidents and weather conditions which could impact financial results;

 

•

increases in the price of commodities used in our mining operations could impact our cost of production;

 

•

obtaining governmental permits and approvals for our operations;

 

•

the effects of proposals to regulate greenhouse gas emissions;

 

•

the effects of government regulation;

 

•

the effects of stringent federal and state employee health and safety regulations;

 

•

the effects of mine closing, reclamation and certain other liabilities;

 

•

uncertainties in estimating our economically recoverable coal and gas reserves;

 

•

the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;

 

•

changes in existing federal and state income tax regulations;

 

•

increased exposure to employee related long-term liabilities;

 

•

minimum funding requirements by the Pension Protection Act of 2006 (the Pension Act) coupled with the significant investment and plan asset losses suffered during the recent economic decline has exposed us to making additional required cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate;

 

•

lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan;

 

•

our ability to comply with laws or regulations requiring that we post security for workers’ compensation and other statutory requirements;

 

•

acquisitions that we recently have made or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made;

 

•

the anti-takeover effects of our rights plan could prevent a change of control;

 

•

risks in exploring for and producing gas;

 

•

new gas development projects and exploration for gas in areas where we have little or no proven gas reserves;

 

•

the disruption of pipeline systems which deliver our gas;

 

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•

the availability of field services, equipment and personnel for drilling and producing gas;

 

•

replacing our natural gas reserves which if not replaced will cause our gas reserves and gas production to decline;

 

•

costs associated with perfecting title for gas rights in some of our properties;

 

•

other persons could have ownership rights in our advanced gas extraction techniques which could force us to cease using those techniques or pay royalties;

 

•

our ability to acquire water supplies needed for drilling, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental rules;

 

•

the coalbeds and other strata from which we produce methane gas frequently contain impurities that may hamper production;

 

•

the enactment of severance tax on natural gas in states in which we operate may impact results of existing operations and impact the economic viability of exploiting new gas drilling and production opportunities;

 

•

prior to the Acquisition, the location of a vast majority of our gas producing properties are in three counties in southwestern Virginia, making us vulnerable to risks associated with having our gas production concentrated in one area;

 

•

our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;

 

•

our ability to extend the maturities of and increase the sizes of our revolving credit facilities; and

 

•

other factors discussed under “Risk Factors,” in this prospectus supplement, including our ability to close under the purchase agreement and integrate the acquired business.

 

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WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any reports, statements or other information we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information about the operation of the SEC Public Reference Room in Washington, D.C. by calling the SEC at (800) 732-0330. Our filings are also available to the public from the website maintained by the SEC at http://www.sec.gov. Our common stock is listed and traded on the New York Stock Exchange, or the NYSE, under the trading symbol “CNX.” Our reports, proxy statements and other information can also be read at the offices of the NYSE, 20 Broad Street, New York, New York 10005.

The SEC’s rules allow us to “incorporate by reference” information into this prospectus supplement and the accompanying prospectus, which means that we can disclose important information to you by referring you to other documents that CONSOL Energy has filed separately with the SEC. The information incorporated by reference is deemed to be part of this prospectus supplement. Information that CONSOL Energy files later with the SEC will automatically update and supersede the information contained in documents filed earlier with the SEC or contained in this prospectus supplement. We incorporate by reference into this prospectus supplement the documents listed below and any future filings made by us with the SEC under Sections 13(a), 13(c), 14 and 15(d) of the Securities Exchange Act of 1934, as amended, after the initial filing of this prospectus supplement and prior to the time that we sell all of the securities offered by this prospectus supplement:

 

•

our Annual Report on Form 10-K for the year ended December 31, 2009;

 

•

our Current Reports on Forms 8-K with report dates as follows: March 12, 2010, March 19, 2010 (2 reports), March 21, 2010 and March 22, 2010;

 

•

the description of CONSOL Energy’s common stock contained in its registration statement on Form 8-A12B filed with the SEC on March 24, 1999 (file no. 001-14901) together with the description of the associated preferred stock purchase rights included in CONSOL’S registration statement on Form 8-A12G filed with the SEC on December 22, 2003 as amended on February 26, 2009 and October 28, 2009; and

 

•

all documents filed by CONSOL Energy pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act with the SEC from the date of this prospectus supplement.

You may obtain copies, without charge, of documents incorporated by reference in this prospectus supplement and the accompanying prospectus, by requesting them from us in writing or by telephone as follows:

CNX Center

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

Telephone: 724-485-4000

www.consolenergy.com

Exhibits to the filings will not be sent, unless those exhibits have been specifically incorporated by reference in this prospectus supplement.

General information about CONSOL Energy, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website at www.consolenergy.com as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Other information contained on our website is not incorporated into this prospectus supplement or our other securities filings and is not a part of these filings.

 

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RISK FACTORS

Our business is subject to various risks and uncertainties. Any of these individual risks described below, or any number of these risks occurring simultaneously, could have a material effect on our Consolidated Financial Statements, business or results of operation. You should carefully consider these factors, as well as the other information contained or incorporated by reference in this document, when evaluating your investment in our securities.

Risks Related to our Business

Continued weakness in global economic conditions or in any of the industries in which our customers operate, or sustained uncertainty in financial markets may have material adverse impacts on our business and financial condition that we currently cannot predict.

As widely reported, economic conditions in the United States and globally have deteriorated and the extent and timing of a recovery, especially in the United States and Europe, is uncertain. Financial markets in the United States, Europe and Asia have also experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in security prices, severely diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government and other governments. Unemployment has risen while business and consumer confidence have declined and there are fears of a prolonged recession in the United States and Europe. Although we cannot predict the impacts, continued weakness in the United States or global economies, in any of the industries we serve or in the financial markets could materially adversely affect our business and financial condition. For example:

 

•

the demand for natural gas in the United States has declined and may remain at low levels or further decline if economic conditions remain weak and continue to negatively impact the revenues, margins and profitability of our natural gas business;

 

•

the demand for electricity in the United States and for steel globally has declined and may remain at low levels or further decline if economic conditions remain weak and continue to negatively impact the revenues, margins and profitability of our steam and metallurgical coal businesses;

 

•

the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and the amount of receivables eligible for sale pursuant to our accounts receivable facility may decline;

 

•

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

 

•

our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

A significant or extended decline in the prices CONSOL Energy receives for our coal and gas could adversely affect our operating results and cash flows.

Our financial results are significantly affected by the prices we receive for our coal and gas. Extended or substantial price declines for coal would adversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. Prices of coal may fluctuate due to factors beyond our control such as overall domestic and global economic conditions; the consumption pattern of industrial consumers, electricity generators and residential users; technological advances affecting energy consumption; domestic and foreign government regulations; price and availability of alternative fuels; price of foreign imports and weather conditions. Any adverse change in these factors could result in weaker demand and possibly lower prices for our production, which would reduce our revenues.

 

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Gas prices are closely linked to consumption patterns of the electric generation industry and certain industrial and residential patterns where gas is the principal fuel. Natural gas prices are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. If we choose not to engage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging arrangements to a greater extent than we do. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as: the domestic and foreign supply of natural gas; the price of foreign imports; overall domestic and global economic conditions; the consumption pattern of industrial consumers, electricity generators and residential users; weather conditions; technological advances affecting energy consumption; domestic and foreign governmental regulations; proximity and capacity of gas pipelines and other transportation facilities; and the price and availability of alternative fuels. Many of these factors may be beyond our control. Lower natural gas prices may not only decrease our revenues on a per unit basis, but may also limit our access to capital. A significant decrease in price levels for an extended period would negatively affect us in several ways including our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production; and access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

If customers do not extend existing contracts, do not honor existing contracts, or do not enter into new long-term contracts for coal, profitability of CONSOL Energy’s operations could be affected.

During the year ended December 31, 2009, approximately 91% of the coal CONSOL Energy produced was sold under long-term contracts (contracts with terms of one year or more). If a substantial portion of CONSOL Energy’s long-term contracts are modified or terminated or if force majeure is exercised, CONSOL Energy would be adversely affected if we are unable to replace the contracts or if new contracts are not at the same level of profitability. If existing customers do not honor current contract commitments, our revenue would be adversely affected. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, CONSOL Energy may not be able to obtain long-term agreements at favorable prices (compared to either market conditions, as they may change from time to time, or our cost structure) and long-term contracts may not contribute to our profitability.

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

For the year ended December 31, 2009, we derived over 25% of our total revenues from sales to our four largest coal customers. At December 31, 2009, we had approximately 16 coal supply agreements with these customers that expire at various times from 2010 to 2028. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may

 

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not be successful and these customers may not continue to purchase coal from us under long-term coal supply agreements. If any one of these four customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.

Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Some power plant owners may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly, our $165 million accounts receivable securitization program and our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.

Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to provide access to markets. Disruption of transportation services because of weather-related problems, strikes, lock-outs, break-downs of locks and dams or other events could temporarily impair our ability to supply coal to customers and adversely affect our profitability. Transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make our coal less competitive.

Competition within the coal and gas industries may adversely affect our ability to sell our products. A loss of our competitive position because of overcapacity in these industries could adversely affect pricing which could impair our profitability.

CONSOL Energy competes with coal producers in various regions of the United States and with some foreign coal producers for domestic sales primarily to power generators. CONSOL Energy also competes with both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power. CONSOL Energy sells coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.

Increases in coal prices could encourage existing producers to expand capacity or for new producers to enter the market. If overcapacity results, prices could fall or we may not be able to sell our coal, which would reduce revenue.

The gas industry is intensely competitive with companies from various regions of the United States and we may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, our operating results and financial position may be adversely affected. For example, one of our competitive strengths is being a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive strength in that area. In addition, larger companies may be able to pay more to acquire new gas properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new gas resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

 

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We could be negatively affected if we fail to maintain satisfactory labor relations.

As of December 31, 2009, we had 8,012 employees. Approximately 35% of these employees are represented by unions. Union operations generated 46% of our U.S. coal production during the year ended December 31, 2009. Relations with our employees and, where applicable, organized labor is important to our success. If we do not maintain satisfactory labor relations with our organized and non-union employees, we may incur strikes, other work stoppages or have reduced productivity. Our labor costs may increase relative to other coal companies which could adversely affect our ability to compete with other coal companies and our results of operations.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards. These standards are continually under review by international, federal and state agencies, related to coal combustion. As a result, coal users may switch to other alternative fuel or alternative energy sources, which would affect the volume of CONSOL Energy’s coal sales.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fired electric generating plants could increase the costs of using coal thereby reducing demand for coal as a fuel source, the volume of our coal sales and price. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future.

For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which power generators switch to alternative fuel could materially affect us if we cannot offset the cost of sulfur removal by lowering the delivered costs of our higher sulfur coals on an energy equivalent basis.

Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to alternative fuels. The Environmental Protection Agency continues to require reduction of nitrogen oxide emissions in a number of eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates. In addition, Congress and several states may consider legislation to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. Any new or proposed reductions will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative to the planning and building of utility power plants in the future. In addition, utilities may favor building new power plants fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fueled generators. Apart from alternative fuel sources, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by domestic electric power generators as a result of new or proposed requirements or a switch to alternative fuels or renewable energy sources could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

 

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CONSOL Energy may not be able to produce sufficient amounts of coal to fulfill our customers’ requirements, which could harm our relationships with customers and could cause our inability to satisfy our contractual demands.

CONSOL Energy may not be able to produce sufficient amounts of coal to meet customer demand, including amounts that we are required to deliver under long-term contracts. CONSOL Energy’s inability to satisfy contractual obligations could result in our customers initiating claims against us.

Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We compete in international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars. As a result, mining costs in competing producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. Currency fluctuations among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.

Coal mining is subject to conditions or events beyond CONSOL Energy’s control, which could cause our financial results to deteriorate.

CONSOL Energy’s coal mining operations are predominantly underground mines. These mines are subject to conditions or events beyond CONSOL Energy’s control that could disrupt operations and affect production and the cost of mining at particular mines for varying lengths of time. These conditions or events may have a significant impact on our operating results. Conditions or events have included:

 

•

variations in thickness of the layer, or seam, of coal;

 

•

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;

 

•

equipment failures or repairs;

 

•

fires and other accidents; and

 

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weather conditions.

A decrease in the availability or increase in the costs of key services, capital equipment or commodities such as steel, liquid fuels and rubber products could impact our cost of production and decrease our anticipated profitability.

Coal mines consume large quantities of key services, capital equipment and commodities (including steel, copper, rubber products and liquid fuels). Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for these services and products are strongly impacted by the global market. A rapid or significant increase in their cost could impact our mining costs because we have a limited ability to negotiate lower prices, and, in some cases, do not have a ready substitute.

For mining and drilling operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which can be a costly and time consuming process and can result in restrictions on our operations.

Most producers in the eastern U.S. are being impacted by government regulations and enforcement to a much greater extent than a few years ago, particularly in light of the renewed focus by environmental agencies and the government generally on the mining industry, including more stringent enforcement of the laws that regulate mining. The pace with which government issues permits needed for new operations and for on-going operations to continue mining has negatively impacted expected production, especially in Central Appalachia.

 

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Environmental groups in Southern West Virginia and Kentucky have challenged state and U.S. Army Corps of Engineers permits for mountaintop mining on various grounds. The most recent challenges have focused on the adequacy of the Corps of Engineers analysis of impacts to streams and the adequacy of mitigation plans to compensate for stream impacts resulting from valley fill permits required for mountaintop mining. In 2007, the U.S. District Court for the Southern District of West Virginia found other operators’ permits for mining in these areas to be deficient. In February 2009, the U.S. Court of Appeals for the Fourth Circuit reversed that decision, finding that the permits were adequate. However, since that reversal, the U.S. Environmental Protection Agency (EPA) began to more critically review valley fill permits and has been recommending that a number of permits be denied because of alleged concerns by EPA of potential impacts to water quality in streams below valley fills, with cumulative impacts of mining on watersheds and with adequacy of mitigation EPA’s objections and an enhanced review process that is being implemented under a federal multi-agency memorandum of understanding have effectively held up the issuance of permits for all types of mining operations that require valley fill permits, including surface facilities for underground mines, without any indication as to when normal permitting will resume. CONSOL Energy’s surface and underground operations have been impacted to a limited extent to date, but future permits will likely be delayed by the EPA’s current position, which will likely adversely impact our surface operations. In addition, over the past few years, the length of time needed to bring a new mine into production has increased by several years because of the increased time required to obtain necessary permits. New safety laws and regulations have impacted productivity at underground mines, although the company has not yet been able to ascertain the exact amount of the impact.

Proposals to regulate greenhouse gas emissions could impact the market for our fossil fuels, increase our costs and reduce the value of our coal and gas assets.

Global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs), such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal and gas we produce, results in the creation of carbon dioxide that is currently emitted into the atmosphere by coal and gas end users, such as coal-fired electric generation power plants. Several actions have been taken at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. For example, EPA has: (i) issued a requirement for specified sources of GHGs to report GHGs annually to EPA commencing in March 2011; (ii) issued an “endangerment” finding that GHGs threaten both public health and the public welfare; and (iii) proposed to regulate certain large sources of GHGs under various permitting programs, in each case pursuant to the Clean Air Act. Several states individually and in some cases under regional alliances, have adopted measures requiring reduction of GHGs within state or regional boundaries. Further regulation of GHGs could occur in the United States pursuant to legislation, treaty obligations, or states enacting new laws and regulations. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (including the United States but has not been ratified by the United States) expires in 2012 and negotiations are underway for a new protocol. President Obama has pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050. He also pledged the United States to be a world leader on GHG reduction and has taken action to re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. Congress is considering comprehensive legislation to regulate and reduce GHG emissions in part under a cap and trade system, and recently proposals have been introduced to ban or at least delay action by EPA to regulate GHGs under the CAA. Litigation seeking to control GHGs also is on the increase. For example, two United States Courts of Appeals have ruled that certain public and private parties can pursue claims that GHG emissions constitute a public nuisance and seek to recover alleged related damages. To the extent actions are taken to reduce GHGs emission by the United States, individual states, or in other countries where we sell coal, or as a result utilities have difficulty obtaining financing in connection with coal-fired plants, the use of and demand for fossil fuels, particularly coal, may be adversely affected which could have a material adverse effect on our results of operations, cash flows and financial condition.

 

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Regulation of GHGs could also impact our coalbed methane operations. Coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane enhances the GHG effect to a greater degree than carbon dioxide. Our gas operations capture coalbed methane from our underground coal mines, although some coalbed methane is vented into the atmosphere when the coal is mined. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines. The amount of coalbed methane we capture is recorded, on a voluntarily basis, with the U.S Department of Energy. We have recorded the amounts we have captured since the early 1990’s and our subsidiary, CNX Gas, has registered as an offset provider of credits with the Chicago Climate Exchange. If regulation of GHGs does not give us credit for capturing methane that would otherwise be released into the atmosphere at our coal mines, any value associated with our historical or future credits would be reduced or eliminated.

Existing and future government laws, regulations and other legal requirements relating to protection of the environment, health and safety matters and others that govern our business increase our costs of doing business for both coal and gas, and may restrict our operations.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in our mines, control of surface subsidence from underground mining and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position. In addition, we could incur substantial costs as a result of violations under environmental and health and safety laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment and health and safety matters could further affect our costs of operations and competitive position.

For example, the federal Clean Water Act and corresponding state laws affect coal mining and gas operations by imposing restrictions on discharges into regulated surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. The Clean Water Act and corresponding state laws (including those relating to protection of “impaired waters” so designated by individual states through the use of new effluent limitations known as Total Maximum Daily Load (“TMDL”) limits; anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting “discharges” which result in degradation; and requirements to treat discharges from coal mining properties for non-traditional pollutants requiring expensive treatment technologies, such as total dissolved solids, chlorides and selenium; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from the surface impacts of underground mining) may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows or may prevent us from being able to mine portions of our reserves. The Clean Water Act is being used by opponents of mountain top removal mining as a means to challenge permits. Also, beginning in early 2009, EPA has relied upon the Clean Water Act to become more actively involved in the permitting of mountain top removal mining operations and other coal mining operations requiring permits to place fill in streams. In addition, CONSOL Energy incurs and will continue to incur significant costs associated with the investigation and remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past.

 

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Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.

Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations and may place restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order our operations to be shut down based on safety considerations.

Stringent health and safety standards were imposed by federal legislation when the Federal Coal Mine Health and Safety Act of 1969 was adopted. The Federal Coal Mine Safety and Health Act of 1977 expanded the enforcement of safety and health standards of the Coal Mine Health and Safety Act of 1969 and imposed safety and health standards on all (non-coal as well as coal) mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures, mine plans and other matters. The additional requirements of the Mine Improvement and New Emergency Response Act of 2006 (the Miner Act) and implementing federal regulations include, among other things, expanded emergency response plans, providing additional quantities of breathable air for emergencies, installation of refuge chambers in underground coal mines, installation of two-way communications and tracking systems for underground coal mines, new standards for sealing mined out areas of underground coal mines, more available mine rescue teams and enhanced training for emergencies. Most states in which CONSOL Energy operates have programs for mine safety and health regulation and enforcement. We believe that the combination of federal and state safety and health regulations in the coal mining industry is, perhaps, the most comprehensive system for protection of employee safety and health affecting any industry. Most aspects of mine operations, particularly underground mine operations, are subject to extensive regulation. The various requirements mandated by law or regulation can place restrictions on our methods of operations, creating a significant effect on operating costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shut down based on safety considerations.

CONSOL Energy has reclamation, mine closure and gas well plugging obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining and gas well drilling. CONSOL Energy accrues for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities and gas well plugging, which are based upon permit requirements and our experience, were approximately $533 million at December 31, 2009. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.

CONSOL Energy faces uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

There are uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff.

 

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Some of the factors and assumptions which impact economically recoverable reserve estimates include:

 

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geological conditions;

 

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historical production from the area compared with production from other producing areas;

 

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the assumed effects of regulations and taxes by governmental agencies;

 

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assumptions governing future prices; and

 

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future operating costs, including cost of materials.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual reserves.

Fairmont Supply Company, a subsidiary of CONSOL Energy, is a co-defendant in various asbestos litigation cases which could result in making payments in the future that are material.

One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time and, in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. For the year ended December 31, 2009, payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOL Energy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.

CONSOL and its subsidiaries are subject to various legal proceedings, which may have a material effect on our business.

We are party to a number of legal proceedings incident to normal business activities. There is the potential that an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position. See Note 24 in the Notes to the Audited Consolidated Financial Statements in Item 8 of our Form 10-K for the year ended December 31, 2009 for further discussion as may be updated by our other filings with the SEC.

Changes in federal or state income tax regulations, particularly in the area of percentage depletion, could cause our financial position and profitability to deteriorate.

The federal government has been reviewing the income tax regulations relating to the coal industry regarding percentage depletion benefits. If the percentage depletion tax benefit was reduced or eliminated, CONSOL Energy’s financial position could be materially impacted.

 

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CONSOL Energy has obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in CONSOL Energy being required to expense greater amounts than anticipated.

CONSOL Energy provides various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2009, the current and non-current portions of these obligations included:

 

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postretirement medical and life insurance ($2.8 billion);

 

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coal workers’ black lung benefits ($194.6 million);

 

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salaried retirement benefits ($192.0 million); and

 

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workers’ compensation ($179.3 million).

However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salaried retirement benefits are funded in accordance with ERISA regulations. The other obligations are unfunded. In addition, the federal government and several states in which we operate consider changes in workers’ compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense.

Due to our participation in a multi-employer pension plan, we have exposure under that plan that extends beyond what our obligation would be with respect to our employees.

Certain of our subsidiaries are obligated to contribute to a multi-employer defined benefit pension plan for United Mine Workers of America (UMWA) retirees. In the event of a partial or complete withdrawal by us from such pension plan, we would be liable for a proportionate share of such pension plan’s unfunded vested benefits, as determined by the plan’s actuary. Based on the limited information available from the plan’s administrators, which we cannot independently validate, we believe that our portion of the contingent liability represented by the pension plan’s unfunded vested benefits, in the case of our withdrawal from the pension plan or the termination of the pension plan, could be material to our financial position and results of operations. In the event that any other contributing employer withdraws from such pension plan and such employer (or any member in its controlled group) cannot satisfy their obligations under the plan at the time of withdrawal, then we, along with the other remaining contributing employers, would be liable for a proportionate share of the pension plan’s unfunded vested benefits at the time of our withdrawal from the pension plan or its termination.

The minimum funding level requirements of the Pension Protection Act of 2006 (Pension Act) applicable to single employer and multi-employer defined benefit pension plans, coupled with significant investment asset losses suffered by such pension plans during the recent decline in equity markets and the current volatile economic environment, have exposed CONSOL Energy to having to make additional cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate.

CONSOL Energy sponsors a defined benefit retirement plan that covers substantially all of our employees not participating in multi-employer pension plans. For this pension plan, the Pension Act requires a funding target of 100% of the present value of accrued benefits. The Pension Act includes a funding target phase-in provision that establishes a funding target of 96% in 2010 and 100% thereafter for our defined benefit pension plan. Any such plan with a funded ratio of less than 80%, or less than 70% using special assumptions, will be deemed to be “at risk” and will be subject to additional funding requirements under the Pension Act. The volatile economic environment and the deterioration in the equity markets have caused investment income and the value of investment assets held in our pension trust to decline and lose value. As a result, CONSOL Energy may be required to increase the amount of cash contributions it makes into the pension trust in order to meet the funding level requirements of the Pension Act.

 

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Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan negotiated with the UMWA and contained in the National Bituminous Coal Wage Agreement (the “NBCWA”). The NBCWA currently calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The current contribution rates called for by the NBCWA are: $4.25 per hour worked in 2009, $5.00 per hour worked in 2010, and $5.50 per hour worked in 2011. These multi-employer pension plan contributions are expensed as incurred. The Pension Act requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan. If the plan was determined to have a funded ratio of less than 80% it will be deemed to be “endangered” or “seriously endangered”, and if less than 65%, it will be deemed to be in “critical” status, and will in either case be subject to additional funding requirements. Under the Pension Act, the multi-employer plan’s actuary must certify the plan’s funded status for each plan year. Based on an estimated funded percentage of 91.4%, a certification was provided by the multi-employer plan actuary, stating that the 1974 Pension Trust was in neither “endangered” nor “critical” status for the plan year beginning July 1, 2008. However, the volatile economic environment and the rapid deterioration in the equity markets caused investment income and the value of investment assets held in the 1974 Pension Trust to decline and lose value.

In late 2008, the Worker, Retiree and Employer Recovery Act of 2008 (“WRERA”) was enacted. Under WRERA, a plan is permitted temporarily to avoid applying the Pension Act’s requirements for improving its financial status by giving a plan the option to elect to retain its prior year zone status and to freeze the plan’s zone status at the level determined for 2008. WRERA also required that the plan’s actuary certify the plan’s actual zone status for 2009. On September 28, 2009, based on an estimated funded percentage of 74%, the 1974 Pension Trust’s actuary provided the Pension Act zone certification for 2009, certifying that the 1974 Pension Trust is “seriously endangered” for the plan year beginning July 1, 2009. Thereafter, pursuant to WRERA, the 1974 Pension Trust elected to retain its 2008 funded status of neither “endangered” nor “critical” for the plan year beginning July 1, 2009. If the freeze election had not been made, the 1974 Pension Trust’s zone status for 2009 as certified by its actuary would have been “seriously endangered” and the 1974 Pension Trust would have been required to develop a funding improvement plan.

The freeze election only applies for the current plan year of 2009. If the 1974 Pension Trust is certified to be in endangered, seriously endangered or critical status for the plan year beginning July 1, 2010, steps will have to be taken under the Pension Act to improve its funded status. Such a determination would require certain subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results.

If lump sum payments made to retiring salaried employees pursuant to CONSOL Energy’s defined benefit pension plan exceed the total of the service cost and the interest cost in a plan year, CONSOL Energy would need to make an adjustment to operating results equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum payment in that year, which may result in an adjustment that could materially reduce operating results.

CONSOL Energy’s defined benefit pension plan for salaried employees allows such employees to receive a lump-sum distribution for benefits earned up through December 31, 2005 in lieu of annual payments when they retire from CONSOL Energy. Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for Terminations Benefits requires that if the lump-sum distributions made for a plan year exceed the total of the service cost and interest cost for the plan year, CONSOL Energy would need to recognize for that year’s results of operations an adjustment equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum in that year. This type of adjustment may result in a material reduction in operating results.

 

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Various federal or state laws and regulations require CONSOL Energy to obtain surety bonds or to provide other assurance of payment for certain of our long-term liabilities including mine closure or reclamation costs, workers’ compensation, coal workers’ black lung and other postemployment benefits.

Federal and state laws and regulations require us to provide surety bonds or provide other assurances to secure payment of certain long-term obligations including mine closure or reclamation costs, water treatment costs, federal and state workers’ compensation costs and other miscellaneous obligations. The requirements and amounts of security are not fixed and can vary from year to year. For certain requirements, there have been periods in the past when it has been difficult for us to secure new surety bonds or renew such bonds without posting collateral. CONSOL Energy has satisfied our obligations under these statutes and regulations by providing letters of credit or other assurances of payment. The issuance of letters of credit under our revolving credit facility reduces amounts that we can borrow under our revolving credit facility for other purposes.

Acquisitions that we have completed, acquisitions that we may undertake in the future, as well as expanding existing company mines involve a number of risks, any of which could cause us not to realize the anticipated benefits.

We have completed several acquisitions and mine and gas expansions in the past. We continually seek to grow our business by adding and developing coal and gas reserves through acquisitions, and by expanding the production at existing mines and existing gas operations. If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Mine expansion, gas operation expansion and acquisition transactions involve various inherent risks, including:

 

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Uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities;

 

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The potential loss of key customers, management and employees of an acquired business;

 

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The ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity;

 

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Problems that could arise from the integration of the acquired business; and

 

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Unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or the acquisition opportunity.

CONSOL Energy’s rights plan may have anti-takeover effects that could prevent a change of control.

On December 19, 2003, CONSOL Energy adopted a rights plan which, in certain circumstances, including a person or group acquiring, or the commencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 15% of the outstanding shares of CONSOL Energy common stock, would entitle each right holder to receive, upon exercise of the right, shares of CONSOL Energy common stock having a value equal to twice the right exercise price. For example, at an exercise price of $80 per right, each right not otherwise voided would entitle its holders to purchase $160 worth of shares of CONSOL Energy common stock for $80. Assuming that shares of CONSOL Energy common stock had a per share value of $16 at such time, the holder of each right would be entitled to purchase ten shares of CONSOL Energy common stock for $80, or a price of $8 per share, one half its then market price. This and other provisions of CONSOL Energy’s rights plan could make it more difficult for a third party to acquire CONSOL Energy, which could hinder stockholders’ ability to receive a premium for CONSOL Energy stock over the prevailing market prices.

 

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We face uncertainties in estimating proved recoverable gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.

Natural gas reserves requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on historical average prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:

 

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geological conditions;

 

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changes in governmental regulations and taxation;

 

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assumptions governing future prices;

 

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the amount and timing of actual production;

 

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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 reserves as of December 31, 2009 would decrease from $1.5 billion to $1.4 billion. The standardized Generally Accepted Accounting Principle measure associated with this decline of $0.10 per thousand cubic feet, would be approximately $0.8 billion.

Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2009, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

 

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Our exploration and development activities may not be commercially successful.

The exploration for and production of gas involves numerous risks. The cost of drilling, completing and operating wells for coal bed methane (CBM) or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

 

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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 or other accidents;

 

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adverse weather conditions;

 

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reductions in natural gas prices;

 

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pipeline ruptures; and

 

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unavailability or high cost of drilling rigs, other field services and equipment.

Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues.

Our focus on new development projects in our operating areas and other unexplored areas increases the risks inherent in our gas and oil activities.

We have little or no proved reserves in certain areas in Pennsylvania, Kentucky and Tennessee. These exploration, drilling and production activities will be subject to many risks, including the risk that CBM or other natural gas is not present in sufficient quantities in the coal seam or target strata, or that sufficient permeability does not exist for the gas to be produced economically. We have invested in property, and will continue to invest in property, including undeveloped leasehold acreage, that we believe will result in projects that will add value over time. Drilling for CBM, other natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. We cannot be certain that the wells we drill in these new areas will be productive or that we will recover all or any portion of our investments.

Our business depends on transportation facilities owned by others. Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our gas.

We transport our gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, reducing our profitability. If we cannot access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. If our sales are reduced because of transportation constraints, our revenues will be reduced, and our unit costs will also increase. If we cannot obtain transportation capacity and we do not have the ability to store gas, we may have to reduce production. If pipeline quality tariffs change, we might be required to install additional processing equipment which could increase our costs. The pipeline could curtail our flows until the gas delivered to their pipeline is in compliance.

 

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Increased industry activity may create shortages of field services, equipment and personnel, which may increase our costs and may limit our ability to drill and produce from our natural gas properties.

The demand for well service providers, related equipment, and qualified and experienced field personnel to drill wells and conduct field operations, including geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These shortages may lead to escalating prices, the possibility of poor services, inefficient drilling operations, and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.

We may incur additional costs and delays to produce gas because we have to acquire additional property rights to perfect our title to the gas estate.

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. Most of these properties were acquired primarily for the coal rights, and, in many cases were acquired years ago. While chain of title work for the coal estate was generally fully developed, in many cases, the gas estate title work is less robust. Our practice is to perform a thorough title examination of the gas estate before we commence drilling activities and to acquire any additional rights needed to perfect our ownership of the gas estate for development and production purposes. We may incur substantial costs to acquire these additional property rights and the acquisition of the necessary rights may not be feasible in some cases. Our inability to obtain these rights may adversely impact our ability to develop those properties. Some states permit us to produce the gas without perfected ownership under an administrative process known as “pooling,” which require us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce gas on acreage that we control and these costs may be material. Further, the pooling process is time-consuming and may delay our drilling program in the affected areas.

Our shale gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the well-bore, and our CBM gas drilling and production operations require the removal and disposal of water from the coal seams, from which we produce gas. If we are unable to dispose of the water we use or remove from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

New environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells, such as proposals in Congress to eliminate the exemption of this practice from regulation under the Safe Drinking Water Act, may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.

Coal seams, frequently contain water that must be removed in order for the gas to detach from the coal and flow to the wellbore. Further, we must remove the water that we use to fracture our shale gas wells when it flows back to the well-bore. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of waste, including, produced water, drilling fluids and other wastes associated with the exploration, development and production of natural gas.

 

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Coalbed methane and other gas that we produce often contains impurities that must be removed, and the gas must be processed before it can be sold, which can adversely affect our operations and financial performance.

A substantial amount of our gas needs to be processed in order to make it saleable to our intended customers. At times, the cost of processing this gas relative to the quantity of gas produced from a particular well, or group of wells, may outweigh the economic benefit of selling that gas. Our profitability may decrease due to the reduced production and sale of gas.

Enactment of a severance tax in several states where we have operations, including Pennsylvania, on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in those states.

As a result of a funding gap in the Pennsylvania state budget due to significant declines in anticipated tax revenues, the Pennsylvania governor has proposed to its legislature the adoption of a wellhead or severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is 5 percent of the value of the natural gas at wellhead plus 4.7 cents per thousand cubic feet of natural gas severed. In Pennsylvania we have rights in significant acreage for coalbed methane and other natural gas extraction on which we have drilled and expect to continue to drill producing wells. In 2009, 17% or 18.4 billion cubic feet, of our production was from Pennsylvania. In addition, a significant amount of our Marcellus shale play acreage is in Pennsylvania. We cannot predict whether Pennsylvania (or any other states) will adopt any such tax, nor if adopted the rate of tax. If states adopt such taxes, it could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities.

Currently the majority of our producing properties are located in three counties in southwestern Virginia, making us vulnerable to risks associated with having our production concentrated in one area.

The vast majority of our producing properties are geographically concentrated in three counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a portion of our expected production. As of December 31, 2009, we had hedges on approximately 47.5 billion cubic feet of our 2010 natural gas production, 22.6 billion cubic feet of our 2011 natural gas production and 15.1 billion cubic feet of our 2012 natural gas production. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.

In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

•

our production is less than expected;

 

•

the counterparties to our contracts fail to perform the contracts; or

 

•

the creditworthiness of our counterparties or their guarantors is substantially impaired.

If our gas hedges would no longer qualify for hedge accounting, we will be required to mark them to market and recognize the adjustments through current year earnings. This may result in more volatility in our income in future periods.

 

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Risks related to the Acquisition

If we do not complete the Acquisition on or prior to June 10, 2010 (subject to an extension to September 8, 2010 in certain circumstances), the purchase agreement may be terminated and we will be required to redeem the senior notes purchased in the senior notes offering.

We may not be able to consummate the Acquisition within the timeframe specified in the purchase agreement as described below. Our ability to consummate the Acquisition is subject to various closing conditions, some of which are beyond our control and we may not be able to complete the Acquisition. If we are not able to consummate the Acquisition on or prior to June 10, 2010, which may be extended to September 8, 2010 in certain instances, or the purchase agreement is terminated at any time prior to that date, we will be required to redeem 100% of the aggregate principal amount of the senior notes. Changes in our business or financial condition, or the terms of the Acquisition or the financing thereof, between the closing of this equity offering and the closing of the Acquisition will have no effect on your rights as a purchaser of the common stock pursuant to this equity offering. If the Acquisition does not close or is terminated, management will have broad discretion over the proceeds of this offering.

Business uncertainties and contractual restrictions while the Acquisition is pending may have an adverse effect on us and the Dominion E&P Business.

Uncertainty about the effect of the Acquisition on employees, suppliers, partners, regulators and customers may have an adverse effect on the Dominion E&P Business. These uncertainties may impair the Dominion E&P Business’ ability to attract, retain and motivate key personnel until the Acquisition is consummated and could cause suppliers, customers and others that deal with the Dominion E&P Business to defer purchases or other decisions concerning the Dominion E&P Business or seek to change existing business relationships with the Dominion E&P Business.

Risks relating to the combined company after the Acquisition

We may not realize the benefits of integrating our companies.

The Acquisition will involve the integration of our operations with the operations of the Dominion E&P Business and the uncertainties inherent in such an integration. Integration will require substantial management attention and could detract attention from the day-to-day business of the combined company. We could encounter difficulties in the integration process, such as the need to revisit assumptions about reserves, future production, revenues, capital expenditures and operating costs, including synergies, the loss of key employees or commercial relationships or the need to address unanticipated liabilities. If we cannot successfully integrate our business with the Dominion E&P Business, we may fail to realize the expected benefits of the Acquisition.

Our level of indebtedness may adversely affect operations and limit our growth.

Following the Acquisition, we will be more leveraged than we have been historically. At December 31, 2009, on a pro forma basis giving effect to the Acquisition, we would have had approximately $3.7 billion of total debt. This level of indebtedness could result in CONSOL Energy having difficulty accessing capital markets or raising capital on favorable terms and CONSOL Energy’s financial results could be negatively affected by its inability to raise capital or because of the cost of such capital.

Our substantial debt following the Acquisition could have important consequences for us. For example, it could:

 

•

increase our vulnerability to general adverse economic and industry conditions;

 

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•

limit our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments on our debt or to comply with any restrictive terms of our debt;

 

•

limit our flexibility in planning for, or reacting to, changes in the industry in which we operate; or

 

•

place us at a competitive disadvantage as compared to our competitors that have less debt.

Realization of any of these factors could adversely affect our financial condition.

If we are unable to generate sufficient cash flow or otherwise obtain funds necessary to make required payments on our indebtedness or if we otherwise fail to comply with the various covenants in such indebtedness, including covenants in our senior secured credit facilities, outstanding notes or the senior notes, we would be in default. This default would permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under our indebtedness, including the senior notes, or result in our bankruptcy. Such defaults, or any bankruptcy resulting therefrom, could result in a default on any such indebtedness and could delay or preclude payment of principal of, or interest on, such indebtedness, including the notes. Our ability to meet our obligations will depend upon our future performance, which will be subject to prevailing economic conditions, commodity prices, and to financial, business and other factors, including factors beyond our control.

Upon consummation of the Acquisition, we and all of our restricted subsidiaries must comply with various restrictive covenants contained in our revolving credit facilities, the indentures related to our existing notes and the senior notes, and any of our future debt arrangements. These covenants will, among other things, limit our ability and the ability of all of our restricted subsidiaries to:

 

•

incur additional debt or liens;

 

•

pay dividends;

 

•

make payments in respect of or redeem or acquire any debt or equity issued by us;

 

•

sell assets;

 

•

make loans or investments; and

 

•

acquire or be acquired by other companies.

The market price of our common stock may decline as a result of the Acquisition.

The market price of our common stock may decline as a result of the Acquisition if, among other things:

 

•

the operational estimates in connection with the integration of the Dominion E&P Business are not realized;

 

•

the transaction costs related to the Acquisition are greater than expected; or

 

•

the financing related to the Acquisition is on unfavorable terms.

The market price of our common stock also may decline if we do not achieve the perceived benefits of the Acquisition as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the Acquisition on our financial results is not consistent with the expectations of financial or industry analysts.

 

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Risks Related to Our Common Stock

We have not identified any specific use of the net proceeds of this offering of shares of common stock in the event the Acquisition and/or the acquisition of shares of CNX Gas which we do not own are not completed.

Consummation of the Acquisition is subject to a number of conditions and there is no assurance that we will close the Acquisition. In addition, there is no assurance that we will acquire the shares of CNX Gas which we do not own. Our board of directors and management will have broad discretion over the use of the proceeds we receive in this offering and might not apply the proceeds in ways that increase the market price of our common stock. Because the primary purpose of this offering of shares of common stock is to provide funds to pay a portion of the consideration for the Acquisition as well as a portion of the consideration of the acquisition of shares of CNX Gas which we do not own, we have not identified a specific use for the proceeds in the event the Acquisition does not occur and/or we do not acquire the shares of CNX Gas which we do not own. Any funds received may be used by us for any corporate purpose, which may include pursuit of other business combinations, expansion of our operations, repayment of existing debt, share repurchases or other uses. The failure of our management to use the net proceeds from this offering of shares of common stock effectively could have a material adverse effect on our business and may have an adverse effect on our earnings per share.

This offering of shares of common stock is expected to be dilutive in the event the Acquisition is not completed, and there may be future dilution of our common stock.

Except as described under the heading “Underwriting,” we are not restricted from issuing additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent the right to receive common stock. As part of this offering, we expect to issue 38,500,000 shares of common stock (or up to 44,275,000 shares of common stock if the underwriters exercise their over-allotment option in full). We intend to use the net proceeds from this offering, along with proceeds from the senior notes offering, to finance the Acquisition and the acquisition of the shares of CNX Gas, which we do not own and as otherwise described under “Use Of Proceeds.” However, we expect that this offering may have a dilutive effect on our earnings per share in the event that the Acquisition is not completed. The actual amount of such dilution cannot be determined at this time and will be based on numerous factors.

Our ability to pay dividends on our common stock may be limited.

Under the Delaware General Corporation Law, we may pay dividends, in cash or otherwise, only if we have surplus in an amount at least equal to the amount of the relevant dividend payment. Any payment of cash dividends will depend upon our financial condition, capital requirements, earnings and other factors deemed relevant by our board of directors. Further, our revolving credit facility limits our ability to pay cash dividends and the indenture governing the senior notes will restrict our ability to pay cash dividends. Agreements governing future indebtedness will likely contain restrictions on our ability to pay cash dividends.

Our stock price has been and continues to be volatile.

The market price for our common stock could fluctuate due to various factors. These factors include:

 

•

announcements relating to significant corporate transactions;

 

•

fluctuations in our quarterly and annual financial results;

 

•

operating and stock price performance of companies that investors deem comparable to us;

 

•

changes in government regulation or proposals relating thereto;

 

•

general industry and economic conditions; and

 

•

sales or the expectation of sales of a substantial number of shares of our common stock in the public market.

 

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In addition, the stock markets have, in recent years, experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stock is traded. Market fluctuations, as well as economic conditions, have adversely affected, and may continue to adversely affect, the market price of our common stock.

There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.

We are not restricted from issuing additional shares of our common stock or preferred stock, subject to the lock-up agreement with the underwriters, including any securities that are convertible into or exchangeable for, or that represent the right to receive, common stock or preferred stock or any substantially similar securities. The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market after this offering or the perception that such sales could occur. Provisions in our charter documents could make it more difficult to acquire our company.

Our restated certificate of incorporation and amended and restated bylaws contain provisions that may discourage, delay or prevent a third party form acquiring us, even if doing so would be beneficial to our shareholders.

Under our amended and restated bylaws, only our board of directors may call special meetings of shareholders, and shareholders must comply with advance notice requirements for nominating candidates for election to our board of directors or for proposing matters that can be acted upon by shareholders at shareholder meetings. Additionally, agreements with certain of our executive officers may have the effect of making a change of control more expensive and, therefore, less attractive.

Pursuant to our restated certificate of incorporation, our board of directors may by resolution establish one or more series of preferred stock, having such number of shares, designation, relative voting rights, dividend rates, conversion rights, liquidation or other rights, preferences and limitations as may be fixed by our board of directors without any further shareholder approval. Such rights, preferences, privileges and limitations as may be established could have the further effect of impeding or discouraging the acquisition of control of our company.

 

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THE ACQUISITION AND RELATED FINANCING TRANSACTIONS

The Acquisition

On March 14, 2010, our wholly-owned subsidiary, CONSOL Energy Holdings LLC VI, entered into a purchase agreement pursuant to which it agreed to acquire the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion), except for certain assets located in natural gas storage fields. CONSOL Energy agreed to guarantee its subsidiary’s obligations under the purchase agreement. We agreed to pay Dominion $3.475 billion for the Dominion E&P Business, subject to certain customary adjustments described in the purchase agreement. In addition, we estimate that we are assuming approximately $110 million of liabilities in the transaction, consisting primarily of asset retirement obligations, additional pension and post-employment benefits liabilities and litigation reserves.

The consummation of the Acquisition and the other transactions contemplated by the purchase agreement are subject to certain conditions, including (i) subject to certain materiality exceptions, the accuracy of the respective representations and warranties of CONSOL Energy and Dominion and compliance by CONSOL Energy and Dominion with their respective obligations under the purchase agreement; (ii) the receipt of all material consents and approvals of any governmental authorities (including those required under the Hart-Scott- Rodino Act) required to consummate the transactions contemplated by the purchase agreement; and (iii) the receipt by Dominion and us of certain documents and agreements from the other parties. The consummation of the transactions contemplated by the purchase agreement is not subject to any financing condition. The purchase agreement contains customary representations and warranties, covenants and indemnification obligations of the parties.

The foregoing description of the purchase agreement and the transactions contemplated thereby is a summary and is subject to and qualified in its entirety by reference to the complete text of the purchase agreement, a copy of which is attached to the Form 8-K filed by us with a report date of March 12, 2010 as Exhibit 2.1 and the terms of which are incorporated by reference.

Financing

In connection with entering into the purchase agreement, we amended our revolving credit facility and our receivables purchase facility. In addition, we received the bridge loan financing commitment described below, and are also raising $2,750,000,000 through the issuance of senior notes through a private placement simultaneously with the closing of this equity offering, the terms of which are described below.

Revolving Credit Facility and Receivables Purchase Facility

The Company’s revolving credit facility and receivables purchase facility were amended in order to permit the Acquisition and indebtedness incurred in connection with the Acquisition. Additionally, changes are being made in the revolving credit facility with respect to various covenants and financial ratios to take into effect the Acquisition as well as increasing the applicable margin added to the interest rate on borrowings and the fee rate on letters of credit. Additionally, with some limited exceptions, the assets acquired in the Acquisition will become collateral under the revolving credit facility and under the Company’s 7.875% notes due 2012. We also plan to increase the size of our revolving credit facility up to $1.5 billion, although no commitments to do so are currently in place. There can be no assurances that we will be able to increase these facilities or extend their maturities.

Concurrent Offering

Concurrently with this offering of common stock, we are offering $2,750,000,000 aggregate principal amount of senior notes, which we refer to as the senior notes in this prospectus supplement, in accordance with Rule 144A and Regulation S under the Securities Act of 1933, as amended. All of our subsidiaries that guarantee

 

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indebtedness under our revolving credit facility will be guarantors of the senior notes on a senior basis. Neither the completion of the senior notes offering nor the completion of this offering is contingent on the completion of the other. The net proceeds of the senior notes will be deposited into escrow pending completion of the Acquisition. We plan to use the net proceeds from the senior notes offering together with the net proceeds of this offering as described under “Use of Proceeds.”

The concurrent offering of senior notes will not be registered under the Securities Act of 1933, as amended, or the securities laws of any other jurisdiction, and the senior notes may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The senior notes will only be offered to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act and outside the United States pursuant to Regulation S under the Securities Act. This description and other information in this prospectus supplement regarding our concurrent offering of senior notes is included in this prospectus supplement solely for informational purposes. Nothing in this prospectus supplement should be construed as an offer to sell, or the solicitation of an offer to buy, any senior notes.

Bridge Loan Commitment

CONSOL Energy received a financing commitment from Banc of America Bridge LLC and PNC Bank, National Association, for a $3.5 billion unsecured bridge facility, which will be available if and to the extent CONSOL Energy does not receive sufficient proceeds from this equity offering, the senior notes offering or any alternate financing to fund the Acquisition and will be guaranteed by the same subsidiaries of CONSOL Energy that guarantee the revolving credit facility. The bridge facility, if drawn, will mature initially on the first anniversary of the closing of the Acquisition, but may be pre-paid, without penalty, at any time prior to that date. The bridge facility will be reduced by the proceeds of debt and equity issuances, including the proceeds of this equity offering and the senior notes offering. If the bridge facility has not been repaid by the one year anniversary of the closing of the Acquisition, then any outstanding loans thereunder will be extended automatically to a maturity date of January 15, 2015, provided that such loans may be exchanged by the lenders for exchange notes due on January 15, 2015. The availability of the bridge facility is subject to a number of customary conditions.

Additional Bank Financings

We are negotiating with the lenders under the Company’s revolving credit facility to increase the aggregate amount which we may borrow at any one time outstanding up to $1.5 billion and to extend its maturity date to 2014. We are also negotiating with the lenders under CNX Gas’ revolving credit facility to increase the aggregate amount which we may borrow at any one time outstanding up to $500 million and extend its maturity date to 2014. Although we do not have commitments for these changes, and no assurances can be given that we will be able to achieve them, we anticipate entering into amendments for these changes concurrently with the closing of the Acquisition.

The foregoing descriptions of the amendment to the revolving credit facility, receivables purchase facility and bridge facility and the transactions contemplated thereby are not complete and are subject to and qualified in their entirety by reference to the complete text of the amendment to the revolving credit facility, the receivables purchase facility, and the termsheet for the bridge facility, copies of which are attached to the Form 8-K filed by us with a report date of March 12, 2010, and the terms of which are incorporated by reference herein.

 

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USE OF PROCEEDS

Unless otherwise indicated in the applicable prospectus supplement, we estimate that the net proceeds from this equity offering, after deducting underwriters’ discounts and commissions and other estimated offering expenses payable by us, will be approximately $1,589.8 million. We intend to use the net proceeds from this common stock offering and the senior notes offering to fund the consideration for the Acquisition and pay related fees and expenses. We also intend to use the net proceeds from this offering to fund a portion of the acquisition of the shares of CNX Gas which we do not own and for general corporate purposes. If we do not complete the Acquisition and/or the acquisition of shares of CNX Gas which we do not own, we intend to use the proceeds for general corporate purposes, which may include the financing of future acquisitions, capital expenditures, additions to working capital, repurchases, repayment or refinancing of debt or stock repurchases.

 

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CAPITALIZATION

The table below sets forth as of December 31, 2009:

 

(i)

the cash and cash equivalents and capitalization of CONSOL Energy;

 

(ii)

the cash and cash equivalents and capitalization of the Dominion E&P Business;

 

(iii)

on an as adjusted basis, CONSOL Energy’s cash and cash equivalents and capitalization after giving effect to the Acquisition and related financing transactions as if they occurred as of such date.

This table should be read in conjunction with “Use of Proceeds” and “Summary Unaudited Pro Forma Combined Financial Information” appearing elsewhere in this prospectus supplement, as well as our audited consolidated financial statements and related notes, which are included in this prospectus supplement and the Dominion E&P Business’ audited consolidated financial statements included in into this prospectus supplement.

 

		As of December 31, 2009
(In thousands)		Actual			As Adjusted
Cash and cash equivalents		$	65,607		$	976,243
Revolving credit facility (CONSOL Energy)(1)		$	415,000		$	415,000
Revolving credit facility (CNX Gas)(2)			57,850			57,850
Senior secured notes due 2012			249,553			249,553
Baltimore port facility revenue bonds(3)			102,865			102,865
8.00% Senior notes due 2017 offered in concurrent offering			—			1,500,000
8.25% Senior notes due 2020 offered in concurrent offering			—			1,250,000
Advance royalty commitments and other indebtedness			50,335			50,335
Capital lease obligations, including current portion			65,549			66,204
Total debt, including current portion			941,152			3,691,807
Total stockholders’ equity			2,024,479			3,712,079
Total capitalization		$	2,965,631		$	7,403,886

 

(1)

Our $1 billion revolving credit facility matures June 2012. At December 31, 2009, in addition to the borrowings presented above, we had $268.4 million of undrawn letters of credit outstanding. As of March 15, 2010, we had approximately $538 million outstanding under this facility (excluding outstanding letters of credit of $270.9 million).

(2)

CNX Gas’ $200 million revolving credit facility matures October 2010. At December 31, 2009, in addition to the borrowings presented above, CNX Gas had $14.9 million of undrawn letters of credit outstanding. As of March 15, 2010, there was approximately $64.6 million outstanding under this facility (excluding outstanding letters of credit of $14.9 million).

(3)	Comprised of two series of unsecured Baltimore Port Facility revenue bonds, with approximately $30.9 million maturing in December 2010 and approximately $72.0 million maturing in October 2011.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table presents our selected historical consolidated financial data for, and as of the end of, each of the periods indicated. The selected historical consolidated financial data for, and as of the end of, each of the years ended December 31, 2009, 2008, 2007, 2006 and 2005 are derived from our audited Consolidated Financial Statements included in this prospectus supplement. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 2009 as required by the Noncontrolling Interest Topic of the Financial Accounting Standards Board Accounting Standards Codification. The selected historical consolidated financial data does not include the effects of the Acquisition. The selected historical consolidated financial data are not necessarily indicative of the results that may be expected for any future period. The selected historical consolidated financial 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 CONSOL Energy’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated by reference into this prospectus supplement.

STATEMENT OF INCOME DATA

(In thousands except per share data)

 

		For the Years Ended December 31,
		2009				2008				2007				2006				2005
Sales—Outside		$	4,311,791			$	4,181,569			$	3,324,346			$	3,286,522			$	2,935,682
Sales—Purchased Gas			7,040				8,464				7,628				43,973				275,148
Sales—Gas Royalty Interests			40,951				79,302				46,586				51,054				45,351
Freight—Outside			148,907				216,968				186,909				162,761				119,811
Other Income			113,186				166,142				196,728				170,861				107,131
Gain on Sale of 18.5% interest in CNX Gas			—				—				—				—				327,326
Total Revenue and Other Income			4,621,875				4,652,445				3,762,197				3,715,171				3,810,449
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)			2,757,052				2,843,203				2,352,000				2,249,776				2,122,259
Purchased Gas Costs			6,442				8,175				7,162				44,843				278,720
Gas Royalty Interests Costs			32,376				73,962				39,921				41,879				36,501
Freight Expense			148,907				216,968				186,909				162,761				119,811
Selling, General and Administrative Expenses			130,704				124,543				108,664				91,150				80,700
Depreciation, Depletion and Amortization			437,417				389,621				324,715				296,237				261,851
Interest Expense			31,419				36,183				30,851				25,066				27,317
Taxes Other Than Income			289,941				289,990				258,926				252,539				228,606
Black Lung Excise Tax Refund			(728	)			(55,795	)			24,092				—				—
Total Costs			3,833,530				3,926,850				3,333,240				3,164,251				3,155,765
Earnings Before Income Taxes			788,345				725,595				428,957				550,920				654,684
Income Taxes			221,203				239,934				136,137				112,430				64,339
Net Income			567,142				485,661				292,820				438,490				590,345
Less: Net Income Attributable to Noncontrolling Interest			(27,425	)			(43,191	)			(25,038	)			(29,608	)			(9,484	)
Net Income Attributable to CONSOL Energy Inc. Shareholders		$	539,717			$	442,470			$	267,782			$	408,882			$	580,861
Earnings Per Share:
Basic		$	2.99			$	2.43			$	1.47			$	2.23			$	3.17
Dilutive		$	2.95			$	2.40			$	1.45			$	2.20			$	3.13
Weighted Average Number of Common Shares Outstanding:
Basic			180,693,243				182,386,011				182,050,627				183,354,732				183,489,908
Dilutive			182,821,136				184,679,592				184,149,751				185,638,106				185,534,980
Dividends Paid Per Share		$	0.40			$	0.40			$	0.31			$	0.28			$	0.28

 

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BALANCE SHEET DATA

(In thousands)

 

		As of December 31,
		2009				2008				2007				2006			2005
Working (deficiency) capital		$	(487,550	)		$	(527,926	)		$	(333,242	)		$	174,372		$	194,578
Total assets			7,725,401				7,370,458				6,208,090				5,663,332			5,071,963
Short-term debt			472,850				557,700				247,500				—			—
Long-term debt (including current portion)			468,302				490,752				507,208				552,263			442,996
Total deferred credits and other liabilities			3,849,428				3,716,021				3,325,231				3,228,653			2,726,563
CONSOL Energy Inc. Stockholders’ equity			1,785,548				1,462,187				1,214,419				1,066,151			1,025,356

 

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COMMON STOCK MARKET PRICES AND DIVIDENDS

Our common stock is listed on the New York Stock Exchange under the symbol CNX. The following table sets forth for the periods indicated the range of high and low sales prices per share of our common stock as reported on the New York Stock Exchange and the cash dividends declared on the common stock for the periods indicated:

 

		High			Low			Dividends
Quarter Period Beginning on January 1, 2010:
Period Ended March 25, 2010		$	58.00		$	42.97		$	0.10
Year Period Ended December 31, 2009:
Quarter Ended March 31, 2009		$	37.66		$	22.47		$	0.10
Quarter Ended June 30, 2009		$	44.13		$	24.01		$	0.10
Quarter Ended September 30, 2009		$	49.84		$	28.60		$	0.10
Quarter Ended December 31, 2009		$	53.50		$	42.18		$	0.10
Year Period Ended December 31, 2008:
Quarter Ended March 31, 2008		$	84.18		$	53.63		$	0.10
Quarter Ended June 30, 2008		$	119.10		$	67.33		$	0.10
Quarter Ended September 30, 2008		$	112.23		$	36.25		$	0.10
Quarter Ended December 31, 2008		$	44.95		$	18.50		$	0.10

As of December 31, 2009, there were 186 holders of record of our common stock. The computation of the approximate number of shareholders is based upon a broker search.

The 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.

 

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UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION

The following unaudited pro forma combined financial information is based on the historical consolidated financial statements of CONSOL Energy, Inc. (CEI) and Dominion Exploration and Production Inc. and subsidiaries, Dominion Reserves Inc. and subsidiaries, and the producing business of Dominion Transmission Inc. (collectively DEPI/DTI), adjusted to reflect the proposed acquisition of DEPI/DTI by CEI and the related financing transactions. The unaudited pro forma combined balance sheet gives effect to the Acquisition of DEPI/DTI by CEI and the related financing transactions as if they had occurred on December 31, 2009. The unaudited pro forma combined statement of operations combine the results of operations of DEPI/DTI and CEI for the year ended December 31, 2009. The unaudited pro forma combined statement of operations gives effect to the following events as if they had occurred on January 1, 2009:

 

•

CEI’s acquisition of DEPI/DTI. The Acquisition will be accounted for using the acquisition method of accounting. Certain assets/liabilities have been excluded from the transaction and are reflected in the “carve-out” adjustments shown on the pro forma statement of operations. The unaudited pro forma combined financial information reflects the preliminary allocation of (1) the fair value of the consideration transferred ($3.475 billion) and (2) the fair value of the underlying assets acquired and liabilities assumed based upon their estimated fair value;

 

•

Borrowings under CEI notes offered (approximately $2.75 billion) and proceeds from equity issuances offered (approximately $1.753 billion; 38,500,000 shares; $45.55 per share) and related issuance fees for both offerings;

 

•

Adjustments to conform the classification of expenses in DEPI/DTI historical statements to CEI’s classification of similar expenses;

 

•

Adjustments for the impact of nonrecurring, non-capitalizable banking and legal fees;

 

•

Adjustments to conform DEPI/DTI historical accounting policies (such as the use of full cost method) to CEI’s accounting policies (successful efforts); and

 

•

Estimated income tax of pro forma adjustments.

The unaudited pro forma combined financial information should be read in conjunction with CEI’s audited financial statements for the year ended December 31, 2009 and DEPI/DTI audited financial statements and the related notes to the financial statements included in this prospectus supplement.

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations or financial position that CEI or the pro forma combined company would have reported had the Acquisition been completed as of the dates set forth in this unaudited pro forma combined financial information and should not be taken as indicative of CEI’s future combined results of operations or financial position. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences between the assumptions used to prepare the unaudited pro forma combined financial information and actual results.

Estimates of fair value assigned on the unaudited pro forma combined financial statements presented are preliminary, and may change.

 

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CONSOL ENERGY

STATEMENT OF INCOME (LOSS)

(000 OMITTED, EXCEPT SHARE AND PER SHARE DATA)

UNAUDITED

 

		CEI As Reported for the year ended December 31, 2009				DEPI/DTI As Reported for the year ended December 31, 2009				Combined Historical for the year ended December 31, 2009				Pro Forma Adjustments										Pro Forma Results for the year ended December 31, 2009
														Carve-Out Adjustments(g)				Buyer Pro Forma Adjustments
Sales—Outside		$	4,311,791			$	298,599			$	4,610,390			$	(38,466	)		$	—					$	4,571,924
Sales—Purchased Gas			7,040				—				7,040				—				—						7,040
Sales—Gas Royalty Interests			40,951				—				40,951				—				—						40,951
Freight—Outside			148,907				—				148,907				—				—						148,907
Other Income			113,186				45,299				158,485				—				—						158,485
Total Revenue and Other Income			4,621,875				343,898				4,965,773				(38,466	)			—						4,927,307
Cost of Goods Sold and Other Operating Charges			2,756,324				61,435				2,817,759				(6,791	)			57,169			a			2,868,137
Purchased Gas Costs			6,442				—				6,442				—				—						6,442
Gas Royalty Interests’ Costs			32,376				—				32,376				—				—						32,376
Freight Expense			148,907				—				148,907				—				—						148,907
Selling, General and Administrative Expense			130,704				36,388				167,092				(8,624	)			—						158,468
Depreciation, Depletion and Amortization			437,417				355,272				792,689				(20,102	)			(214,986	)		b			557,601
Interest Expense			31,419				35,125				66,544				(34,417	)			220,000			c			252,127
Taxes Other Than Income			289,941				4,680				294,621				(1,210	)			—						293,411
Total Costs			3,833,530				492,900				4,326,430				(71,144	)			62,183						4,317,469
Earnings Before Income Taxes			788,345				(149,002	)			639,343				32,678				(62,183	)					609,838
Income Taxes			221,203				(61,394	)			159,809				61,394				(60,816	)		d			160,387
Net Income			567,142				(87,608	)			479,534				(28,716	)			(1,367	)					449,451
Less: Net Income Attributable to
Non Controlling Shareholders			(27,425	)			—				(27,425	)			—				—						(27,425	)
Net Income Attributable to CONSOL Energy Inc. Shareholders		$	539,717			$	(87,608	)		$	452,109			$	(28,716	)		$	(1,367	)				$	422,026
Earnings Per Share:
Basic		$	2.99			$	—			$	2.50													$	1.93
Dilutive		$	2.95			$	—			$	2.47													$	1.91
Weighted Average Number of Common Shares Outstanding:
Basic			180,693,243								180,693,243														219,193,243
Dilutive			182,821,136								182,821,136														221,321,136
Dividends Paid Per Share		$	0.40							$	0.40													$	0.40

 

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CONSOL ENERGY

BALANCE SHEET

(000 OMITTED)

UNAUDITED

 

		CEI As Reported At December 31, 2009			DEPI/DTI As Reported At December 31, 2009				Combined Historical At December 31, 2009			Pro Forma Adjustments										Pro Forma Results Year To Date 2009
												Carve-Out Adjustments(g)				Buyer Pro Forma Adjustments
ASSETS
Current Assets:
Cash and Cash Equivalents		$	65,607		$	36			$	65,643		$	—			$	910,600			e,g,h		$	976,243
Accounts and Notes Receivable:
Trade			317,460			8,665				326,125			(8,665	)			—						317,460
Other Receivables			15,983			30,926				46,909			(30,926	)			—						15,983
Inventories			307,597			1,181				308,778			—				—			g			308,778
Deferred Income Taxes			73,383			(9,212	)			64,171			9,212				—						73,383
Prepaid Expenses			161,006			55,188				216,194			(53,482	)			6,315			f,g			169,027
Total Current Assets			941,036			86,784				1,027,820			(83,861	)			916,915						1,860,874
Property, Plant and Equipment:
Property, Plant and Equipment			10,681,955			1,683,346				12,365,301			(53,923	)			1,952,539			g			14,263,917
Less—Accumulated Depreciation, Depletion and Amortization			4,557,665			678,476				5,236,141			(21,734	)			(656,742	)		g			4,557,665
Total Property, Plant and Equipment—Net			6,124,290			1,004,870				7,129,160			(32,189	)			2,609,281			g			9,706,252
Other Assets:
Deferred Income Taxes			425,297			(266,079	)			159,218			266,079				—						425,297
Investment in Affiliates			83,533			925				84,458			(925	)			—						83,533
Other			151,245			55,440				206,685			(53,391	)			43,636			f,g			196,930
Total Other Assets			660,075			(209,714	)			450,361			211,763				43,636						705,760
TOTAL ASSETS		$	7,725,401		$	881,940			$	8,607,341		$	95,713			$	3,569,832					$	12,272,886

 

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CONSOL ENERGY

BALANCE SHEET

(000 OMITTED)

UNAUDITED

 

		CEI As Reported At December 31, 2009			DEPI/DTI As Reported At December 31, 2009				Combined Historical At December 31, 2009			Pro Forma Adjustments										Pro Forma Results Year To Date 2009
												Carve-Out Adjustments(g)				Buyer Pro Forma Adjustments
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable		$	269,560		$	38,372			$	307,932		$	(38,372	)		$	—					$	269,560
Short-Term Notes Payable			472,850			115,579				588,429			(115,579	)			—						472,850
Current Portion of Long-Term Debt			45,394			—				45,394			—				—						45,394
Accrued Income Taxes			27,944			—				27,944			—				—						27,944
Other Accrued Liabilities			612,838			60,704				673,542			(45,174	)			—			g			628,368
Total Current Liabilities			1,428,586			214,655				1,643,241			(199,125	)			—						1,444,116
Total Long-Term Debt			422,908			528,530				951,438			(528,530	)			2,750,000			h			3,172,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions			2,679,346			—				2,679,346			—				2,800			g			2,682,146
Pneumoconiosis Benefits			184,965			—				184,965			—				—						184,965
Mine Closing			397,320			—				397,320			—				—						397,320
Gas Well Closing			85,992			122,587				208,579			(7,915	)			(24,672	)		g			175,992
Workers’ Compensation			152,486			—				152,486			—				—						152,486
Salary Retirement			189,697			—				189,697			—				900			g			190,597
Reclamation			27,105			—				27,105			—				—						27,105
Other			132,517			50,939				183,456			(50,284	)			—			g			133,172
Total Deferred Credits and Other Liabilities			3,849,428			173,526				4,022,954			(58,199	)			(20,972	)					3,943,783
Total Liabilities			5,700,922			916,711				6,617,633			(785,854	)			2,729,028						8,560,807
Total CONSOL Energy Stockholders’ Equity			1,785,548			(34,771	)			1,750,777			881,567				840,804						3,473,148
Noncontrolling Interest			238,931			—				238,931			—				—						238,931
Total Equity			2,024,479			(34,771	)			1,989,708			881,567				840,804						3,712,079
TOTAL LIABILITIES AND EQUITY		$	7,725,401		$	881,940			$	8,607,341		$	95,713			$	3,569,832					$	12,272,886

 

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Pro forma Footnotes

 

a.	Adjustment includes amortization of debt issuances costs ($6,615), financing and professional fees ($50,000) and exploration costs that DEPI/DTI capitalized under full cost accounting that CONSOL Energy would expense under successful efforts accounting ($854).

 

b.	Adjustment includes the reversal of the ceiling test impairment booked by DEPI/DTI due to assets being stated at fair value ($273,717). Adjustment also includes the additional depreciation, depletion and amortization expense of $58,731 related to the fair value step up of assets.

 

c.	Adjustment reflects the assumed interest expense related to the issuance of $2,750,000 of notes. Increasing the assumed interest rate on the $2,750,000 of notes by 0.50% per year would increase annual interest expense by $13,750 per year.

 

d.	Adjustment reflects the change in CONSOL Energy’s effective tax rate from 28.1% to 26.3%.

 

e.

Adjustment reflect the assumed gross proceeds from notes offering ($2,750,000) and equity offering ($1,753,000), offset by the cash price paid for stock of DEPI/DTI ($3,475,000), notes issuance costs ($52,000), financing and professional fees ($50,000) and additional dividends due after approximately 38,500,000 additional shares being issued ($15,400).

 

f.	Represents the current and long-term portion of prepaid notes issuance fees.

 

g.	The carve-out adjustments include the following items which are excluded from the Acquisition or the purchase agreement provides are retained assets, liabilities, revenues, or expenses of Dominion:

 

•

the accounts receivable, accounts payable, affiliated employer benefit assets, and accrued payroll related reflected on the combined balance sheet are not being acquired because Dominion is entitled to all revenues earned and is responsible for all property costs and payroll and benefit-related obligations incurred on or prior to the closing date, therefore;

 

•

the combined statement of operations includes revenues and operating expenses and the combined balance sheet includes property, plant and equipment and associated accumulated depreciation, depletion and amortization related to certain oil and natural gas wells located in natural gas storage fields which Dominion is retaining;

 

•

the combined statement of operations includes revenues and operating expenses and the combined balance sheet includes futures, options, swaps, and other derivatives assets and liabilities related to derivate contracts which Dominion is responsible for eliminating;

 

•

Dominion is responsible for settling any indebtedness with affiliates prior to closing, therefore affiliated debt and accrued interest reflected on the combined balance sheet and affiliated interest expense reflected in the statement of operations will not exist;

 

•

Dominion is responsible for all income taxes incurred through closing, and has the rights to any income tax refunds or severance tax abatements for taxable periods ending prior to closing, therefore all current and deferred income tax assets and liabilities have been removed from each balance sheet. Thus, income tax amounts reflected in the statement of operations will not exist;

 

•

the combined balance sheet includes prepaid insurance under insurance policies which are excluded assets and will be retained by Dominion;

 

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•

The financial statements include allocated assets and liabilities in order for DTI/E&P to be run as a stand-alone business based on SEC Rule 3-05. However, only the Additional Assets of DTI and Seller Assumed Obligations as defined in the draft PSA are included in the proposed transaction. Therefore, any allocated assets and liabilities not identified in the purchase agreement are being retained by Dominion; and

 

•

Under the terms of the purchase agreement, the Company is acquiring Appalachian reserves and assuming obligations related only to Appalachian properties. Therefore, combined financial statements include non-Appalachian operations that were sold during 2007. In addition, non-Appalachian obligations such as legal claims or remaining obligations from the 2007 sales which are reflected on the combined balance sheet are retained by Dominion.

The preliminary fair value assessment of assets acquired and liabilities assumed is as follows;

 

		Historical After Carve-Out Adjustments				Estimated Fair Value				Pro Forma Adjustment
Cash acquired		$	36			$	36			$	—
Inventory			1,181				1,181				—
Prepaid expenses			1,706				1,706				—
Property, plant and equipment
Proven properties			957,921				1,163,500				205,579
Unproven properties			8,416				2,245,207				2,236,791
Wells and related equipment			5,035				156,071				151,036
Identified intangibles			—				10,247				10,247
Other miscellaneous			1,309				6,937				5,628
Total property, plant and equipment			972,681				3,581,962				2,609,281
Other assets			2,049				—				(2,049	)
Other accrued liabilities			(15,530	)			(15,530	)			—
Other post employment benefits			—				(2,800	)			(2,800	)
Salary retirement			—				(900	)			(900	)
Gas well closing liabilities			(114,672	)			(90,000	)			24,672
Other liabilities			(655	)			(655	)			—
Total Cash Paid						$	3,475,000

 

h.	Represents the principal of the notes issued.

 

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DESCRIPTION OF CAPITAL STOCK

Please read the information discussed under the heading “Description of CONSOL Energy Capital Stock” beginning on page 19 of the accompanying prospectus. As of March 11, 2010 we had 500,000,000 shares of authorized common stock, par value $0.01 per share, of which 181,421,854 shares were outstanding.

 

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MATERIAL U.S. FEDERAL TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following summary describes the material U.S. federal income tax consequences of the Acquisition, ownership and disposition of our common stock to non-U.S. holders (as defined below) that acquire our common stock for cash pursuant to this offer. The summary is based on the Internal Revenue Code of 1986, as amended (the Code), Treasury Regulations, judicial decisions, published positions of the Internal Revenue Service (IRS), and other applicable authorities, all as in effect as of the date hereof and all of which are subject to change or differing interpretations (possibly with retroactive effect). The discussion does not address all of the tax consequences that may be relevant to a particular person or to persons subject to special treatment under U.S. federal income tax laws. In addition, this discussion does not address any state, local or foreign tax consequences or any tax consequences other than U.S. federal income and estate tax consequences. This summary deals only with persons who hold our common stock as capital assets within the meaning of Section 1221 of the Code (generally, property held for investment). No IRS ruling has been or is expected to be sought regarding any matter discussed herein. Holders are urged to consult their tax advisors as to the particular U.S. federal tax consequences to them of the Acquisition, ownership and disposition of our common stock, as well as the effects of state, local and non-U.S. tax laws.

A “non-U.S. holder” is a person or entity that, for U.S. federal income tax purposes, is a:

 

•

non-resident alien individual, other than certain former citizens and residents of the United States subject to tax as expatriates,

 

•

foreign corporation or

 

•

foreign estate or trust.

If a partnership (including any entity treated as a partnership or other pass-through entity for U.S. federal income tax purposes) is a holder of our common stock, the U.S. federal income tax treatment of a partner in the partnership generally will depend on the status of the partner and the activities of such partnership. Partners and partnerships should consult their tax advisors as to the particular U.S. federal income tax consequences applicable to them.

Distributions

Distributions on common stock will constitute dividends for U.S. federal income tax purposes to the extent such distributions are made out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. We will be required to withhold U.S. federal withholding tax at a rate of 30% (or at a lower rate under an applicable income tax treaty that allows for a reduced rate of withholding, provided that we have received proper certification that the non-U.S. holder is eligible for the reduced rate under such income tax treaty) from the gross amount of the dividends paid to a non-U.S. holder unless such dividends are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States (and, in the case of certain tax treaties, are attributable to a permanent establishment or fixed base within the United States) and the non-U.S. holder complies with applicable certification and disclosure requirements, as described below.

Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under an applicable income tax treaty and the manner of claiming the benefits of such treaty. A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by timely filing an appropriate claim for a refund with the IRS.

Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States (and, in the case of certain tax treaties, are attributable to a permanent establishment or fixed base within the United States) are not subject to the U.S. federal withholding tax, but, unless otherwise provided in an

 

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applicable income tax treaty, are instead taxed in the manner applicable to U.S. persons. In that case, we will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements. In addition, dividends received by a foreign corporation that are effectively connected with the conduct of a trade or business in the United States may be subject to a branch profits tax at a 30% rate, or at a lower rate if provided by an applicable income tax treaty.

Dispositions

Subject to the discussion below regarding information reporting and backup withholding, a non-U.S. holder generally will not be subject to U.S. federal income taxation with respect to gain realized on the sale, exchange or other disposition of our common stock, unless:

 

(1)

the non-U.S. holder holds our common stock in connection with the conduct of a U.S. trade or business (and, in the case of certain tax treaties, the gain is attributable to a permanent establishment or fixed base within the United States); or

 

(2)

in the case of an individual, such individual is present in the United States for 183 days or more during the taxable year in which the gain is realized and certain other conditions are met; or

 

(3)

we are or have been a “U.S. real property holding corporation” for U.S. federal income tax purposes, and such non-U.S. holder held more than 5 percent (5%) of our common stock at any time during the shorter of the five-year period ending on the date of disposition or the period that such non-U.S. holder held our common stock.

An individual non-U.S. holder described in (1) immediately above will be subject to tax on the net gain derived from the sale under regular graduated U.S. federal income tax rates. An individual non-U.S. holder described in (2) immediately above will be subject to a flat 30% tax on the gain derived from the sale, which may be offset by U.S. source capital losses, even though the individual is not considered a resident of the United States. If a non-U.S. holder that is a foreign corporation falls under (1) immediately above, it will be subject to tax on its net gain in the same manner as if it were a United States person as defined under the Code and, in addition, may be subject to the branch profits tax equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty.

Except with respect to any non-U.S. holder who actually or constructively owns more than five percent (5%) of our common stock, we are not a U.S. real property holding corporation because our common stock is regularly traded on an established securities market.

Information reporting and backup withholding

A non-U.S. holder not subject to U.S. income tax may nonetheless be subject to backup withholding and information reporting with respect to distributions on our common stock, and with respect to amounts realized on the disposition of our common stock within the United States or through certain United States-related financial intermediaries, unless (except as described below) the non-U.S. holder provides the withholding agent with the applicable IRS Form W-8 (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person as defined under the Code) or otherwise establishes an exemption. Non-U.S. holders should consult their tax advisors as to their qualifications for an exemption for backup withholding and the procedure for obtaining such an exemption. In general, we must report to the IRS and to each non-U.S. holder the dividends paid to such non-U.S. holder and the tax, if any, withheld with respect to such dividends. Copies of the information or returns reporting such dividends and withholding may also be made available to the tax authorities in the country in which the non-U.S. holder resides under the provisions of an applicable income tax treaty.

 

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Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules from a payment to a non-U.S. holder may be credited against the non-U.S. holder’s U.S. federal income tax liability, if any, or refunded, if the required information is furnished to the IRS in a timely manner. Non-U.S. holders should consult their tax advisors regarding the application of information reporting and backup withholding rules to them.

Federal estate tax

Individual non-U.S. holders and entities the property of which is potentially includible in such an individual’s gross estate for U.S. federal estate tax purposes (for example, a trust funded by such an individual and with respect to which the individual has retained certain interests or powers), should note that, absent an applicable treaty benefit, the common stock will be treated as U.S. situs property subject to U.S. federal estate tax.

 

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UNDERWRITING

Merrill Lynch, Pierce, Fenner & Smith Incorporated is acting as representative of each of the underwriters named below. Subject to the terms and conditions set forth in a purchase agreement among us and the underwriters, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the number of shares of common stock set forth opposite its name below.

 

Underwriter		Number of Shares
Merrill Lynch, Pierce, Fenner & Smith Incorporated		16,170,000
PNC Capital Markets LLC		7,700,000
Scotia Capital (USA) Inc.		5,390,000
Stifel, Nicolaus & Company Incorporated		2,887,500
BMO Capital Markets Corp.		1,540,000
Credit Agricole Securities (USA) Inc.		1,540,000
RBS Securities Inc.		962,500
UBS Securities LLC		770,000
Brean Murray, Carret & Co., LLC		385,000
FBR Capital Markets & Co.		385,000
Howard Weil Incorporated		385,000
Pritchard Capital Partners, LLC		385,000
Total		38,500,000

Subject to the terms and conditions set forth in the purchase agreement, the underwriters have agreed, severally and not jointly, to purchase all of the shares sold under the purchase agreement if any of these shares are purchased. If an underwriter defaults, the purchase agreement provides that the purchase commitments of the nondefaulting underwriters may be increased or the purchase agreement may be terminated.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering the shares, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the shares, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officer’s certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Commissions and Discounts

The representative has advised us that the underwriters propose initially to offer the shares to the public at the public offering price set forth on the cover page of this prospectus supplement and to dealers at that price less a concession not in excess of $.76 per share. After the initial offering, the public offering price, concession or any other term of the offering may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their overallotment option.

 

		Per Share		Without Option		With Option
Public offering price		$42.50		$1,636,250,000		$1,881,687,500
Underwriting discount		$1.275		$49,087,500		$56,450,625
Proceeds, before expenses, to us		$41.225		$1,587,162,500		$1,825,236,875

The expenses of the offering, not including the underwriting discount, are estimated at $1 million and are payable by us. The underwriters have agreed to reimburse us $3.6 million of our expenses related to the Acquisition and related financing transactions.

 

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Overallotment Option

We have granted an option to the underwriters to purchase up to 5,775,000 additional shares at the public offering price, less the underwriting discount. The underwriters may exercise this option for 30 days from the date of this prospectus supplement solely to cover any overallotments. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the purchase agreement, to purchase a number of additional shares proportionate to that underwriter’s initial amount reflected in the above table.

No Sales of Similar Securities

We, our executive officers and directors have agreed not to sell or transfer any common stock or securities convertible into, exchangeable for, exercisable for, or repayable with common stock, for 90 days after the date of this prospectus supplement without first obtaining the written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly

 

•

offer, pledge, sell or contract to sell any common stock,

 

•

sell any option or contract to purchase any common stock,

 

•

purchase any option or contract to sell any common stock,

 

•

grant any option, right or warrant for the sale of any common stock,

 

•

lend or otherwise dispose of or transfer any common stock,

 

•

request or demand that we file a registration statement related to the common stock, or

 

•

enter into any swap or other agreement that transfers, in whole or in part, the economic consequence of ownership of any common stock whether any such swap or transaction is to be settled by delivery of shares or other securities, in cash or otherwise.

New York Stock Exchange Listing

The shares are listed on the New York Stock Exchange under the symbol “CNX.”

Price Stabilization, Short Positions

Until the distribution of the shares is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our common stock. However, the representative may engage in transactions that stabilize the price of the common stock, such as bids or purchases to peg, fix or maintain that price.

In connection with the offering, the underwriters may purchase and sell our common stock in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ overallotment option described above. The underwriters may close out any covered short position by either exercising their overallotment option or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they

 

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may purchase shares through the overallotment option. “Naked” short sales are sales in excess of the overallotment option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of shares of common stock made by the underwriters in the open market prior to the completion of the offering.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of our common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Electronic Offer, Sale and Distribution of Shares

In connection with the offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail. In addition, Merrill Lynch, Pierce, Fenner & Smith Incorporated may facilitate Internet distribution for this offering to certain of its Internet subscription customers. Merrill Lynch, Pierce, Fenner & Smith Incorporated may allocate a limited number of shares for sale to its online brokerage customers. An electronic prospectus is available on the Internet web site maintained by Merrill Lynch, Pierce, Fenner & Smith Incorporated. Other than the prospectus in electronic format, the information on the Merrill Lynch, Pierce, Fenner & Smith Incorporated website is not part of this prospectus supplement.

Other Relationships

The underwriters and certain of their affiliates have provided and may in the future provide financial advisory, investment banking and commercial banking services in the ordinary course of business to us and certain of our affiliates, for which they receive customary fees and expense reimbursement. Certain of the underwriters or their affiliates are lenders and/or agents under our revolving credit facility. Merrill Lynch, Pierce, Fenner & Smith Incorporated (an affiliate of Banc of America Securities LLC) and PNC Capital Markets LLC are joint book-running managers and certain of the other underwriters are co-managers on our concurrent notes offering. Banc of America Securities LLC is acting as financial advisor to us in connection with the Acquisition. In addition, affiliates of certain of the initial purchasers have committed to provide us with interim financing in the aggregate amount of $3.5 billion. These commitments will be reduced by the net cash proceeds of this offering upon closing of this offering.

Notice to Prospective Investors in the EEA

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of any shares which are the subject of the offering contemplated by this prospectus supplement may not be made in that Relevant Member State,

 

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except that an offer to the public in that Relevant Member State of any shares may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

 

(a)

to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

 

(b)

to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

 

(c)

by the underwriters to fewer than 100 natural or legal persons (other than “qualified investors” as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

 

(d)

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of shares shall result in a requirement for the publication by us or any representative of a prospectus pursuant to Article 3 of the Prospectus Directive.

Any person making or intending to make any offer of shares within the EEA should only do so in circumstances in which no obligation arises for us or any of the underwriters to produce a prospectus for such offer. Neither we nor the underwriters have authorized, nor do they authorize, the making of any offer of shares through any financial intermediary, other than offers made by the underwriters which constitute the final offering of shares contemplated in this prospectus supplement.

For the purposes of this provision, and your representation below, the expression an “offer to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any shares to be offered so as to enable an investor to decide to purchase any shares, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

Each person in a Relevant Member State who receives any communication in respect of, or who acquires any shares under, the offer of shares contemplated by this prospectus supplement will be deemed to have represented, warranted and agreed to and with us and each underwriter that:

 

(A)

it is a “qualified investor” within the meaning of the law in that Relevant Member State implementing Article 2(1)(e) of the Prospectus Directive; and

 

(B)

in the case of any shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (i) the shares acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than “qualified investors” (as defined in the Prospectus Directive), or in circumstances in which the prior consent of the representatives has been given to the offer or resale; or (ii) where shares have been acquired by it on behalf of persons in any Relevant Member State other than qualified investors, the offer of those shares to it is not treated under the Prospectus Directive as having been made to such persons.

In addition, in the United Kingdom, this document is being distributed only to, and is directed only at, and any offer subsequently made may only be directed at persons who are “qualified investors” (as defined in the Prospectus Directive) (i) who have professional experience in matters relating to investments falling within

 

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Article 19 (5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Order”) and/or (ii) who are high net worth companies (or persons to whom it may otherwise be lawfully communicated) falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This document must not be acted on or relied on in the United Kingdom by persons who are not relevant persons. In the United Kingdom, any investment or investment activity to which this document relates is only available to, and will be engaged in with, relevant persons.

Notice to Prospective Investors in Switzerland

This document, as well as any other material relating to the shares which are the subject of the offering contemplated by this prospectus supplement, do not constitute an issue prospectus pursuant to Article 652a and/or 1156 of the Swiss Code of Obligations. The shares will not be listed on the SIX Swiss Exchange and, therefore, the documents relating to the shares, including, but not limited to, this document, do not claim to comply with the disclosure standards of the listing rules of SIX Swiss Exchange and corresponding prospectus schemes annexed to the listing rules of the SIX Swiss Exchange. The shares are being offered in Switzerland by way of a private placement, i.e., to a small number of selected investors only, without any public offer and only to investors who do not purchase the shares with the intention to distribute them to the public. The investors will be individually approached by the issuer from time to time. This document, as well as any other material relating to the shares, is personal and confidential and do not constitute an offer to any other person. This document may only be used by those investors to whom it has been handed out in connection with the offering described herein and may neither directly nor indirectly be distributed or made available to other persons without express consent of the issuer. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in (or from) Switzerland.

Notice to Prospective Investors in the Dubai International Financial Centre

This document relates to an exempt offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority. This document is intended for distribution only to persons of a type specified in those rules. It must not be delivered to, or relied on by, any other person. The Dubai Financial Services Authority has no responsibility for reviewing or verifying any documents in connection with exempt offers. The Dubai Financial Services Authority has not approved this document nor taken steps to verify the information set out in it, and has no responsibility for it. The shares which are the subject of the offering contemplated by this prospectus supplement may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this document you should consult an authorised financial adviser.

 

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LEGAL MATTERS

The validity of the shares of common stock offered by this prospectus supplement will be passed upon for us by Buchanan Ingersoll & Rooney PC, Pittsburgh, PA. Certain legal matters in connection with the offering will be passed upon for the underwriters by Cahill Gordon & Reindel LLP, New York, New York.

EXPERTS

CONSOL Energy Inc.

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

The consolidated financial statements of CONSOL Energy Inc. and its subsidiaries appearing in CONSOL Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009 (the “Form 10-K”) (including the schedule appearing therein), and the effectiveness of CONSOL Energy Inc.’s internal control over financial reporting as of December 31, 2009 have been audited by Ernst & Young LLP, an independent registered public accounting firm, as set forth in its reports thereon, included therein, and incorporated herein by reference. Such consolidated financial statements are incorporated herein by reference in reliance upon such reports given on the authority of such firms as experts in accounting and auditing.

The consolidated financial statements of CONSOL Energy Inc. and its subsidiaries at December 31, 2007 and for the year then ended, included in and incorporated by reference in this prospectus supplement from CONSOL Energy Inc.’s Form 10-K, including the financial statement schedule at December 31, 2007 included by reference therein, have been so incorporated in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in accounting and auditing.

INDEPENDENT CONSULTING FIRMS

The information included and incorporated by reference in this prospectus supplement relating to the proved reserves of gas and oil (including coal bed methane) of CONSOL Energy as of December 31, 2008, 2007, 2006 and 2005 and as of March 31, 2005, is derived from reserve reports prepared or reviewed by Schlumberger Data and Consulting Services. The information included and incorporated by reference in this prospectus supplement relating to the proved reserves of gas and oil (including coal bed methane) of CONSOL Energy, owned through CNX Gas Corporation, a majority owned subsidiary of CONSOL Energy, as of December 31, 2009, is derived from internal estimates, which estimates were audited by Netherland, Sewell & Associates, Inc. This information is included and incorporated by reference in this prospectus in reliance upon these firms as experts in matters contained in the reports.

Dominion E&P Business

INDEPENDENT AUDITORS

The combined financial statements of the Dominion E&P Business as of December 31, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, included in and incorporated by reference in this prospectus have been audited by Deloitte & Touche, LLP, independent auditors, as stated in their report, and are included in and incorporated by reference in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

INDEPENDENT CONSULTING FIRMS

Certain information with respect to the oil and natural gas reserves associated with the Dominion E&P Business’ oil and natural gas properties appearing in CONSOL Energy Inc.’s Form 8-K with a report date of March 19, 2010 is derived from the report of Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm. This information is included or incorporated by reference in this prospectus supplement in reliance upon these firms as experts in matters contained in the report.

 

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INDEX TO FINANCIAL STATEMENTS

CONSOL Energy Inc. Consolidated Financial Statements

 

		Page
Reports of Independent Registered Public Accounting Firms		F-2
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 and 2007		F-4
Consolidated Balance Sheets at December 31, 2009 and 2008		F-5
Consolidated Statements of Stockholders’ Equity for the Years Ended December  31, 2009, 2008 and 2007		F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		F-7
Notes to Audited Consolidated Financial Statements		F-8

Dominion E&P Business

 

		Page
Reports of Independent Registered Public Accounting Firm		F-79
Combined Statements of Income for the Years Ended December 31, 2009, 2008 and 2007		F-80
Combined Balance Sheets at December 31, 2009 and 2008		F-81
Combined Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		F-83
Combined Statements of Stockholders’ Equity and Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007		F-84
Notes to Audited Combined Financial Statements		F-85

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of CONSOL Energy Inc.

We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. (and Subsidiaries) as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CONSOL Energy Inc. (and Subsidiaries) at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements. As discussed in Note 15 to the consolidated financial statements, during the year ended December 31, 2008, the Company adopted the measurement provisions related to pension and other postretirement benefit obligations.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), CONSOL Energy, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 9, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 9, 2010

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of CONSOL Energy Inc.:

In our opinion, the consolidated statements of income, stockholders’ equity and cash flows for the year ended December 31, 2007 present fairly, in all material respects, the results of CONSOL Energy Inc. and its subsidiaries (CONSOL Energy) operations and their cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule included in Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of CONSOL Energy’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, CONSOL Energy changed the manner in which it accounts for non-controlling interests effective January 1, 2009.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 18, 2008, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the change in accounting for non-controlling interests discussed in Note 1 to the consolidated financial statements, as to which the date is June 26, 2009.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)

 

		For the Years Ended December 31,
		2009				2008				2007
Sales—Outside		$	4,311,791			$	4,181,569			$	3,324,346
Sales—Purchased Gas			7,040				8,464				7,628
Sales—Gas Royalty Interests			40,951				79,302				46,586
Freight—Outside			148,907				216,968				186,909
Other Income (Note 3)			113,186				166,142				196,728
Total Revenue and Other Income			4,621,875				4,652,445				3,762,197
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)			2,757,052				2,843,203				2,352,000
Purchased Gas Costs			6,442				8,175				7,162
Gas Royalty Interests Costs			32,376				73,962				39,921
Freight Expense			148,907				216,968				186,909
Selling, General and Administrative Expenses			130,704				124,543				108,664
Depreciation, Depletion and Amortization			437,417				389,621				324,715
Interest Expense (Note 4)			31,419				36,183				30,851
Taxes Other Than Income (Note 5)			289,941				289,990				258,926
Black Lung Excise Tax Refund			(728	)			(55,795	)			24,092
Total Costs			3,833,530				3,926,850				3,333,240
Earnings Before Income Taxes			788,345				725,595				428,957
Income Taxes (Note 6)			221,203				239,934				136,137
Net Income			567,142				485,661				292,820
Less: Net Income Attributable to Noncontrolling Interest			(27,425	)			(43,191	)			(25,038	)
Net Income Attributable to CONSOL Energy Inc. Shareholders		$	539,717			$	442,470			$	267,782
Earnings Per Share (Note 1):
Basic		$	2.99			$	2.43			$	1.47
Dilutive		$	2.95			$	2.40			$	1.45
Weighted Average Number of Common Shares Outstanding (Note 1):
Basic			180,693,243				182,386,011				182,050,627
Dilutive			182,821,136				184,679,592				184,149,751
Dividends Paid Per Share		$	0.40			$	0.40			$	0.31

The accompanying notes are an integral part of these consolidated financial statements.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)

 

		December 31,
		2009				2008
ASSETS
Current Assets:
Cash and Cash Equivalents		$	65,607			$	138,512
Accounts and Notes Receivable:
Trade			317,460				221,729
Other Receivables			15,983				79,552
Inventories (Note 8)			307,597				227,810
Recoverable Income Taxes			—				33,862
Deferred Income Taxes (Note 6)			73,383				60,599
Prepaid Expenses			161,006				221,750
Total Current Assets			941,036				983,814
Property, Plant and Equipment:
Property, Plant and Equipment			10,681,955				9,980,288
Less—Accumulated Depreciation, Depletion and Amortization			4,557,665				4,214,316
Total Property, Plant and Equipment—Net (Note 10)			6,124,290				5,765,972
Other Assets:
Deferred Income Taxes (Note 6)			425,297				333,543
Investment in Affiliates			83,533				72,996
Other			151,245				214,133
Total Other Assets			660,075				620,672
TOTAL ASSETS		$	7,725,401			$	7,370,458
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable		$	269,560			$	385,197
Short-Term Notes Payable (Note 11)			472,850				557,700
Current Portion of Long-Term Debt (Note 13 and Note 14)			45,394				22,401
Accrued Income Taxes			27,944				—
Other Accrued Liabilities (Note 12)			612,838				546,442
Total Current Liabilities			1,428,586				1,511,740
Long-Term Debt:
Long-Term Debt (Note 13)			363,729				393,312
Capital Lease Obligations (Note 14)			59,179				75,039
Total Long-Term Debt			422,908				468,351
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions (Note 15)			2,679,346				2,493,344
Pneumoconiosis Benefits (Note 16)			184,965				190,261
Mine Closing			397,320				404,629
Gas Well Closing			85,992				80,554
Workers’ Compensation (Note 16)			152,486				128,477
Salary Retirement (Note 15)			189,697				194,567
Reclamation			27,105				38,193
Other			132,517				185,996
Total Deferred Credits and Other Liabilities			3,849,428				3,716,021
TOTAL LIABILITIES			5,700,922				5,696,112
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 183,014,426 Issued and 181,086,267 Outstanding at December 31, 2009; 183,014,426 Issued and 180,549,851 Outstanding at December 31, 2008			1,830				1,830
Capital in Excess of Par Value			1,033,616				993,478
Preferred Stock, 15,000,000 authorized, None issued and outstanding			—				—
Retained Earnings			1,456,898				1,010,902
Accumulated Other Comprehensive Loss (Note 19)			(640,504	)			(461,900	)
Common Stock in Treasury, at Cost—1,928,159 Shares at December 31, 2009 and 2,464,575 Shares at December 31, 2008			(66,292	)			(82,123	)
Total CONSOL Energy Inc. Stockholders’ Equity			1,785,548				1,462,187
Noncontrolling Interest			238,931				212,159
TOTAL EQUITY			2,024,479				1,674,346
TOTAL LIABILITIES AND EQUITY		$	7,725,401			$	7,370,458

The accompanying notes are an integral part of these consolidated financial statements.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)

 

		Common Stock				Capital in Excess of Par Value				Retained Earnings (Deficit)				Accumulated Other Comprehensive Income (Loss)				Common Stock in Treasury				Total CONSOL Energy Inc. Stockholders’ Equity				Non- Controlling Interest				Total Equity
Balance at December 31, 2006		$	1,851			$	921,881			$	600,541			$	(375,717	)		$	(82,405	)		$	1,066,151			$	135,659			$	1,201,810
Net Income			—				—				267,782				—				—				267,782				25,038				292,820
Treasury Rate Lock (Net of $52 Tax)			—				—				—				(81	)			—				(81	)			—				(81	)
Gas Cash Flow Hedge (Net of $2,146 Tax)			—				—				—				3,445				—				3,445				769				4,214
Actuarially Determined Long-Term Liability Adjustments (Net of $27,991 Tax)			—				—				—				(46,931	)			—				(46,931	)			(78	)			(47,009	)
Comprehensive Income (Loss)			—				—				267,782				(43,567	)			—				224,215				25,729				249,944
Cumulative Effect of Adoption of Income Tax Uncertainties			—				—				(3,202	)			—				—				(3,202	)			—				(3,202	)
Issuance of Treasury Stock			—				—				(42,110	)			—				61,334				19,224				—				19,224
Issuance of CNX Gas Stock			—				—				—				—				—				—				215				215
Purchases of Treasury Stock			—				—				—				—				(80,157	)			(80,157	)			—				(80,157	)
Purchases of CNX Gas Stock			—				—				—				—				—				—				(1,762	)			(1,762	)
Tax Benefit From Stock-Based Compensation			—				23,682				—				—				—				23,682				16				23,698
Amortization of Stock-Based Compensation Awards			—				20,981				—				—				—				20,981				3,261				24,242
Dividends ($0.31 per share)			—								(56,475	)			—				—				(56,475	)			—				(56,475	)
Balance at December 31, 2007			1,851				966,544				766,536				(419,284	)			(101,228	)			1,214,419				163,118				1,377,537
Net Income			—				—				442,470				—				—				442,470				43,191				485,661
Treasury Rate Lock (Net of $55 Tax)			—				—				—				(77	)			—				(77	)			—				(77	)
Gas Cash Flow Hedge (Net of $77,292 Tax)			—				—				—				97,833				—				97,833				20,813				118,646
Actuarially Determined Long-Term Liability Adjustments (Net of $82,156 Tax)			—				—				—				(140,289	)			—				(140,289	)			(16	)			(140,305	)
Comprehensive Income (Loss)			—				—				442,470				(42,533	)			—				399,937				63,988				463,925
Adoption of Actuarially Determined Long-Term Liability Measurement Provision (Net of $23,652 Tax)			—				—				(38,606	)			(83	)			—				(38,689	)			(18	)			(38,707	)
Issuance of Treasury Stock			—				—				(21,519	)			—				34,980				13,461				—				13,461
Issuance of CNX Gas Stock			—				—				—				—				—				—				312				312
Purchases of Treasury Stock			—				—				—				—				(15,875	)			(15,875	)			—				(15,875	)
Purchases of CNX Gas Stock			—				—				—				—				—				—				(18,682	)			(18,682	)
Retirement of Common Stock (2,112,200 Shares)			(21	)			(16,876	)			(65,022	)			—				—				(81,919	)			—				(81,919	)
Tax Benefit From Stock-Based Compensation			—				22,003				—				—				—				22,003				62				22,065
Amortization of Stock-Based Compensation Awards			—				21,807				—				—				—				21,807				3,379				25,186
Dividends ($0.40 per share)			—				—				(72,957	)			—				—				(72,957	)			—				(72,957	)
Balance at December 31, 2008			1,830				993,478				1,010,902				(461,900	)			(82,123	)			1,462,187				212,159				1,674,346
Net Income			—				—				539,717				—				—				539,717				27,425				567,142
Treasury Rate Lock (Net of $49 Tax)			—				—				—				(83	)			—				(83	)			—				(83	)
Gas Cash Flow Hedge (Net of $34,932 Tax)			—				—				—				(44,270	)			—				(44,270	)			(8,862	)			(53,132	)
Actuarially Determined Long-Term Liability Adjustments (Net of $77,361 Tax)			—				—				—				(134,251	)			—				(134,251	)			(298	)			(134,549	)
Comprehensive Income (Loss)			—				—				539,717				(178,604	)			—				361,113				18,265				379,378
Issuance of Treasury Stock			—				—				(21,429	)			—				15,831				(5,598	)			—				(5,598	)
Issuance of CNX Gas Stock			—				—				—				—				—				—				157				157
Tax Benefit From Stock-Based Compensation			—				2,674				—				—				—				2,674				13				2,687
Amortization of Stock-Based Compensation Awards			—				32,723				—				—				—				32,723				16,658				49,381
Stock-Based Compensation Awards to CNX Gas Employees			—				4,741				—				—				—				4,741				(3,951	)			790
Net Change in Crown Drilling Noncontrolling Interest			—				—				—				—				—				—				(4,370	)			(4,370	)
Dividends ($0.40 per share)			—				—				(72,292	)			—				—				(72,292	)			—				(72,292	)
Balance at December 31, 2009		$	1,830			$	1,033,616			$	1,456,898			$	(640,504	)		$	(66,292	)		$	1,785,548			$	238,931			$	2,024,479

The accompanying notes are an integral part of these consolidated financial statements.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(Dollars in thousands, except per share data)

 

		For the Years Ended December 31,
		2009				2008				2007
Cash Flows from Operating Activities:
Net Income		$	567,142			$	485,661			$	292,820
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization			437,417				389,621				324,715
Stock-based Compensation			39,032				25,186				24,243
Gain on Sale of Assets			(15,121	)			(23,368	)			(112,389	)
Amortization of Mineral Leases			3,970				4,871				4,519
Deferred Income Taxes			47,430				135,594				59,555
Equity in Earnings of Affiliates			(15,707	)			(11,140	)			(6,551	)
Changes in Operating Assets:
Accounts Receivable Securitization			(115,000	)			39,600				125,400
Accounts and Notes Receivable			84,597				(79,747	)			14,074
Inventories			(79,787	)			(53,994	)			13,448
Prepaid Expenses			10,730				(5,032	)			(9,145	)
Changes in Other Assets			(724	)			17,081				40,164
Changes in Operating Liabilities:
Accounts Payable			(70,458	)			64,851				(2,435	)
Other Operating Liabilities			80,527				(14,020	)			(30,978	)
Changes in Other Liabilities			(45,883	)			51,546				(54,924	)
Other			17,286				2,754				1,517
Net Cash Provided by Operating Activities			945,451				1,029,464				684,033
Cash Flows from Investing Activities:
Capital Expenditures			(920,080	)			(1,061,669	)			(743,114	)
Acquisition of AMVEST			—				—				(296,724	)
Proceeds from Sale of Assets			69,884				28,193				84,791
Purchase of Stock in Subsidiary			—				(67,259	)			(10,000	)
Net Investment in Equity Affiliates			4,855				1,879				(7,057	)
Net Cash Used in Investing Activities			(845,341	)			(1,098,856	)			(972,104	)
Cash Flows from Financing Activities:
Payments on Long-Term Debt			—				—				(45,000	)
(Payments on) Proceeds from Short-Term Debt			(84,850	)			310,200				247,500
Payments on Miscellaneous Borrowings			(19,190	)			(10,414	)			(2,935	)
Tax Benefit from Stock-Based Compensation			3,270				22,003				23,682
Dividends Paid			(72,292	)			(72,957	)			(56,475	)
Issuance of Treasury Stock			2,547				15,215				19,224
Purchases of Treasury Stock			—				(97,794	)			(80,157	)
Noncontrolling Interest Member Distribution			(2,500	)			—				—
Net Cash (Used In) Provided By Financing Activities			(173,015	)			166,253				105,839
Net Increase (Decrease) in Cash and Cash Equivalents			(72,905	)			96,861				(182,232	)
Cash and Cash Equivalents at Beginning of Period			138,512				41,651				223,883
Cash and Cash Equivalents at End of Period		$	65,607			$	138,512			$	41,651

The accompanying notes are an integral part of these consolidated financial statements.

See Note 20—Supplemental Cash Flow

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 1—Significant Accounting Policies:

A summary of the significant accounting policies of CONSOL Energy Inc. and subsidiaries (CONSOL Energy) is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.

Basis of Consolidation:

The Consolidated Financial Statements include the accounts of majority-owned and controlled subsidiaries. The accounts of variable interest entities (VIEs) as defined by the Consolidation Topic of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification where CONSOL Energy is the primary beneficiary, are included in the consolidated financial statements. Investments in business entities in which CONSOL Energy does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation.

Use of Estimates:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to other postretirement benefits, coal workers’ pneumoconiosis, workers’ compensation, salary retirement benefits, stock-based compensation, reclamation, mine closure and gas well plugging liabilities, deferred income tax assets and liabilities, contingencies, and coal and gas reserve values.

Cash and Cash Equivalents:

Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.

Trade Accounts Receivable:

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CONSOL Energy reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CONSOL Energy regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectible amounts were not material in the periods presented.

Inventories:

Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead and other related costs. The cost of merchandise for resale is determined by the last-in, first-out (LIFO) method and includes industrial maintenance, repair and operating supplies for sale to third parties. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in our mining operations.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Property, Plant and Equipment:

Property, plant and equipment is carried at cost. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.

Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.

Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities. Costs of developing the first pit within a permitted area of a surface mine are capitalized. A surface mine is defined as the permitted mining area which includes various adjacent pits that share common infrastructure, processing equipment and a common ore body. Surface mine development costs include construction costs for entry roads, drilling, blasting and removal of overburden in developing the first cut for mountain stripping or box cuts for surface stripping. Stripping costs incurred during the production phase of a mine are expensed as incurred.

Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production using the units-of-production method. Depletion of leased coal interests is computed using the units-of-production method over proven and probable coal reserves. Advance mining royalties and leased coal interests are evaluated periodically for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized in other income.

Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted for prospectively as changes in accounting estimates.

Depreciation of mining plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:

 

		Years
Building and improvements		10 to 45
Mine machinery and equipment		3 to 25
Leasehold improvements		Life of Lease

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Costs to obtain coal lands are capitalized based on the fair value at acquisition and are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and accessible to the mine. Proven and probable coal reserves exclude non-recoverable coal reserves and anticipated processing losses. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.

Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Costs for purchased and internally developed software are expensed until it has been determined that the software will result in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed 7 years.

Impairment of Long-lived Assets:

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets’ carrying value. Impairment expense of $4,211 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2009 for the impairment of certain sales contract assets. Impairment expense of $3,773 was recognized in Cost of Goods Sold and Other Operating Charges in December 2008, when it became probable that an option to purchase preferred equity in PFBC Environment Energy Technology would not be exercised.

Income Taxes:

Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CONSOL Energy’s financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of CONSOL Energy’s assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

As required by the Income Tax Topic of the FASB Accounting Standards Codification, CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement, is determined. A previously recognized tax position is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.

Postretirement Benefits Other Than Pensions:

Postretirement benefits other than pensions, except for those established pursuant to the Coal Industry Retiree Health Benefit Act of 1992 (the Health Benefit Act), are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the FASB Accounting Standards Codification which requires employers to accrue the cost of such retirement benefits for the employees’ active service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these benefits. Postretirement benefit obligations established by the Health Benefit Act are treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made. This treatment is in accordance with the Retirement Benefits Compensation (Extractive Activities—Mining) Topic of the FASB Accounting Standards Codification.

Pneumoconiosis Benefits and Workers’ Compensation:

CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers’ pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers’ compensation benefits for employees who sustain employment related physical injuries or some types of occupational disease. Workers’ compensation benefits include compensation for their disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions for estimated benefits are determined on an actuarial basis.

Mine Closing, Reclamation and Gas Well Closing:

CONSOL Energy accrues for reclamation costs, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in the Cost of Goods Sold and Other Operating Charges line on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gas wells, and includes treatment of water and the reclamation of land upon exhaustion of coal and gas reserves.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Accrued mine closing costs, perpetual care costs, reclamation and costs of dismantling and removing gas related facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.

Retirement Plans:

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in the non-contributory defined benefit retirement plan. In lieu of participation in this plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.

Revenue Recognition:

Revenues are recognized when title passes to the customers. For domestic coal sales, this generally occurs when coal is loaded at mine or offsite storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For gas sales, this occurs at the contractual point of delivery. For industrial supplies and equipment sales, this generally occurs when the products are delivered. For terminal, river and dock, land, research and development, and coal waste disposal services, revenue is recognized generally as the service is provided to the customer.

CNX Gas has operational gas-balancing agreements with various interstate pipelines. These imbalance agreements are managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.

CNX Gas sells gas to accommodate the delivery points of its customers. In general this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty which qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are therefore reflected net on the income statement in Cost of Goods Sold and Other Operating Charges.

CNX Gas also provides gathering services to third parties by purchasing gas produced by the third party, at market prices less a fee. The gas purchased from third party producers is then resold by CNX Gas to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as purchased gas revenue and purchased gas costs in the Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX Gas from the third party producer.

Royalty Interest Gas Sales represent the revenues for the portion of production associated with royalty interest owners.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Freight Revenue and Expenses:

Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.

Royalty Recognition:

Royalty expenses for coal rights are included in Cost of Goods Sold and Other Operating Charges when the related revenue for the coal sale is recognized. Royalty expenses for gas rights are included in Gas Royalty Interest Costs when the related revenue for the gas sale is recognized. These royalty expenses are paid in cash in accordance with the terms of each agreement. Revenues for coal and gas sold related to production under royalty contracts, versus owned by CONSOL Energy, are recorded on a gross basis. The recognized revenues for these transactions are not net of related royalty fees.

Contingencies:

CONSOL Energy, or our subsidiaries, from time to time is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.

Treasury Stock:

On September 12, 2008, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $500,000 of the company’s common stock during a twenty-four month period beginning September 9, 2008, and ending September 8, 2010. Shares of common stock repurchased by us are recorded at cost as treasury stock and result in a reduction of stockholders’ equity in our Consolidated Balance Sheets. From time to time, treasury shares may be reissued as part of our stock-based compensation programs. When shares are reissued, we use the weighted average cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from Capital in Excess of Par Value.

On December 21, 2005, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $300,000 of the company’s common stock during a twenty-four month period beginning January 1, 2006 and ending December 31, 2007.

For the years ended December 31, 2008 and 2007, we had cash expenditures under our repurchase program of $97,794 and $80,157, respectively, funded primarily by cash generated from operations. The total common shares repurchased for the years ended December 31, 2008 and 2007 were 2,741,300 and 2,087,800 at an average cost of $35.59 and $38.14 per share, respectively. There were no cash expenditures under our repurchase program for the year ended December 31, 2009.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Stock-Based Compensation:

Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. See Note 18 to the Audited Consolidated Financial Statements for a further discussion on stock-based compensation.

Earnings per Share:

Basic earnings per share are computed by dividing net earnings by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similar to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, and the assumed vesting of restricted and performance stock units if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised, and outstanding restricted and performance stock units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. In accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy includes the impact of the proforma deferred tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock method. The table below sets forth the outstanding options, unvested restricted stock units, and unvested performance stock units that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive.

 

		For the Years Ended December 31,
		2009			2008			2007
Anti-Dilutive Options			695,743			370,987			133,343
Anti-Dilutive Restricted Stock Units			5,274			—			—
Anti-Dilutive Performance Stock Units			41,581			18,176			—
			742,598			389,163			133,343
		For the Years Ended December 31,
		2009			2008			2007
Net income attributable to CONSOL Energy Inc. shareholders		$	539,717		$	442,470		$	267,782
Average shares of common stock outstanding:
Basic			180,693,243			182,386,011			182,050,627
Effect of stock-based compensation awards			2,127,893			2,293,581			2,099,124
Dilutive			182,821,136			184,679,592			184,149,751
Earnings per share:
Basic		$	2.99		$	2.43		$	1.47
Dilutive		$	2.95		$	2.40		$	1.45

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Shares of common stock outstanding were as follows:

 

		2009		2008			2007
Balance, beginning of year		180,549,851		182,291,623			182,654,629
Issuance(1)		536,416		1,027,250			1,755,457
Repurchased-Treasury Stock Shares		—		(656,922	)		(2,118,463	)
Repurchased-Retired Shares		—		(2,112,100	)		—
Balance, end of year		181,086,267		180,549,851			182,291,623

 

(1)	See Note 18—Stock-based Compensation for additional information.

Accounting for Derivative Instruments:

CONSOL Energy accounts for derivative instruments in accordance with the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. This requires CONSOL Energy to measure every derivative instrument (including certain derivative instruments embedded in other contracts) at fair value and record them in the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported, net of applicable taxes, in other comprehensive income. The ineffective portions of hedges are recognized in earnings in the current period.

CONSOL Energy formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in fair values or cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge, or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.

Accounting for Business Combinations:

The company accounts for its business acquisitions under the purchase method of accounting consistent with the requirements of the Business Combination Topic of the FASB Accounting Standards Codification. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.

Accounting for Carbon Emissions Offsets:

In 2008, CNX Gas, an 83.3% subsidiary, completed the independent verification and registration processes necessary to sell carbon emission offsets on the Chicago Climate Exchange. CNX Gas has verified approximately 8.4 million metric tons of offsets, CONSOL Energy has also verified approximately 8.3 million metric tons of offsets which may sell on the over-the-counter market. These offsets are recorded at their historical cost, which is zero. Sales of these emission offsets will be reflected in income as they occur. To date, no offsets have been sold.

Recently Adopted Accounting Guidance:

In December 2009, CONSOL adopted authoritative guidance issued by the FASB on extractive activities for oil and gas reserve estimation and disclosures. The objective of the new guidance is to align the oil and gas reserve estimation and disclosure requirements with the requirements of the Securities and Exchange

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Commission. The new guidance, among other purposes, is primarily intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by expanding the definition of proved oil and gas producing activities, disclosing geographical areas that represent a certain percentage of proved reserves, updating the reserve estimation requirements for changes in practice and technology that have occurred over the past several decades and requiring that an entity continue to disclose separately the amounts and quantities for consolidated and equity method investments. CONSOL has applied this guidance to its Financial Statements for the year ended December 31, 2009.

Recent Accounting Guidance Not Yet Adopted:

In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities, which is effective for CONSOL beginning July 1, 2010. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. We believe adoption of this new guidance will not have material impact on CONSOL’s financial statements.

In June 2009, the FASB issued accounting guidance regarding the accounting for transfers of financial assets that is designed to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance enhances the information provided to financial statement users to provide greater transparency about transfers of financial assets and a transferor’s continuing involvement, if any, with transferred financial assets. The guidance requires enhanced disclosures about the risks that a transferor continues to be exposed to because of its continuing involvement in transferred financial assets. This guidance is effective for an entity’s first annual reporting period after November 15, 2009 and is not eligible for early adoption. Management believes that this guidance will result in the securitization facility transactions being reclassified from sales transactions to secured borrowing transactions as of January 1, 2010.

Reclassifications:

Certain reclassifications of prior period data have been made to conform to the year ended December 31, 2009 as required by the Noncontrolling Interest Topic of the FASB Accounting Standards Codification.

Subsequent Events:

We have evaluated all subsequent events through February 9, 2010, the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.

Note 2—Acquisitions and Dispositions:

In August 2009, CONSOL Energy completed the lease assignment of CNX Gas’, an 83.3% owned subsidiary, previous headquarters. Total expense related to this transaction for the year ended December 31, 2009 was $1,500, which was recognized in the Cost of Goods Sold and Other Operating Charges.

In August 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds from the sale were $16,011, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

In July 2009, CNX Gas leased approximately 20,000 acres having Marcellus Shale potential from NiSource Energy Ventures, LLC, a subsidiary of the Columbia Energy Group, for a cash payment of $8,275 which is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price for the transaction was principally allocated to gas properties and related development.

In June 2009, CONSOL Energy recognized the fair value of the remaining lease payments in the amount of $10,499 in accordance with the Exit or Disposal Cost Obligations topic of the Financial Accounting Standards Board Accounting Standards Codification related to the Company’s previous headquarters. This liability has been recorded in Other Liabilities on the consolidated balance sheet at December 31, 2009. Total expense related to this transaction was $12,500, which was recognized in the Cost of Goods Sold and Other Operating Charges. This amount includes lease payments of $10,974 as well as the removal of a related asset of $1,526. Additionally, $5,832 was recognized in the Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the premises that occurred in 2005.

In February 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds for the sale were $42,282, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

In December 2008, CONSOL Energy completed the acquisition of the outstanding 51% interest in Southern West Virginia Energy, LLC (“SWVE”) for a cash payment of $11,521. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price was principally allocated to property, plant and equipment. SWVE wholly-owns Southern West Virginia Resources, LLC and Minway Contracting, LLC, and had previously been a 49% subsidiary of CONSOL Energy. Prior to the acquisition of the outstanding interest, SWVE had been fully consolidated in accordance with the Consolidation Topic of the Financial Accounting Standards Board Accounting Standards Codification by CONSOL Energy. The proforma results for this acquisition are not material to CONSOL Energy’s financial results.

In November 2008, CONSOL Energy completed the acquisition of North Penn Pipe & Supply, Inc. for a cash payment, net of cash acquired, of $22,550. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. North Penn Pipe & Supply, Inc. is a distributor of oil and gas field equipment, primarily tubular goods, to the northern Appalachian Basin, a region stretching from the state of New York to southwestern Pennsylvania and northern West Virginia. The fair value of merchandise for resale acquired in this acquisition is $10,623 and is included in inventory on the Consolidated Balance Sheets as of the acquisition date. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.

In October 2008 CONSOL Energy Inc.’s Board of Directors has authorized a purchase program for shares of CNX Gas Corporation common stock for an aggregate purchase price of up to $150 million. The authorization, which is not intended to take CNX Gas private, was effective as of October 21, 2008 for a twenty-four month period. During the year ended December 31, 2008, CONSOL Energy completed the purchase of $67,259 of CNX Gas stock on the open market at an average price of $26.53 per share. The purchase of these 2,531,400 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.7% to 83.3% at December 31, 2008. During the year ended December 31, 2007, CONSOL Energy purchased $10,000 of CNX Gas stock on the open market at an average price of $26.87 per share. The purchase of these 372,000 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.5% to 81.7% at December 31, 2007.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

In July 2008, CNX Gas completed the acquisition of several leases and gas wells from KIS Oil & Gas Inc. for a cash payment of $19,324. The purchase price was principally allocated to property, plant and equipment. The sales agreement called for the transfer of 30 oil and gas wells and approximately 5,600 leased acres. This acquisition enhanced our acreage position in Northern Appalachia. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In June 2008, CNX Gas completed the acquisition of the remaining 50% interest in Knox Energy, LLC and Coalfield Pipeline Company not already owned by CNX Gas for a cash payment of $36,000 which was principally allocated to gas properties and related development and gas gathering equipment. Knox Energy, LLC had been proportionately consolidated into CONSOL Energy’s financial statements during 2008. During 2007 the equity method was used to account for these entities. Knox Energy, LLC is a natural gas production company and Coalfield Pipeline Company is a gathering and transportation company with operations in Tennessee. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In February 2008, CONSOL Energy completed the sale of the Mill Creek Mining Complex located in Kentucky. The sales agreement called for the transfer of all of the assets comprising the complex. Cash proceeds from the sale were $14,649, with our basis in the assets being $9,934. Accordingly, a gain of $4,715 was recorded on the transaction.

In December 2007, CONSOL Energy completed a sale/lease-back of 35 river barges. Cash proceeds from the sale were $16,895, with our basis in the equipment being $16,951. Accordingly, a loss of $56 was recorded on the transaction. The lease has been accounted for as an operating lease. The lease term is fourteen years.

In October 2007, CONSOL Energy acquired 100% of the outstanding shares in an oil and gas company for a cash payment of $12,385 which was principally allocated to gas properties and related development and gas gathering equipment. The acquired company is in the business of owning, operating and producing oil and gas wells and related pipelines. The acquired assets consisted of gas wells, equipment and connecting pipelines utilized in well operations. The acquisition was accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In July, 2007, CONSOL Energy acquired 100% of the voting interest of AMVEST Corporation and certain subsidiaries and affiliates (AMVEST) for a cash payment, net of cash acquired, of $296,724 in a transaction accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The coal reserves acquired consisted of approximately 160 million tons of high quality, low sulfur steam and high-volatile metallurgical coal. Also included in the acquisition were four coal preparation plants, several fleets of modern mining equipment and a common short-line railroad that connects the coal preparation plants to the CSX and Norfolk and Southern rail interchanges. The results of operations of the acquired entities are included in CONSOL Energy’s Consolidated Statements of Income as of August 1, 2007.

The AMVEST acquisition, when combined with CONSOL Energy’s adjacent coal reserves, creates a large contiguous block of coal reserves in the Central Appalachian region. Also, included in the acquisition was a highly-skilled workforce proficient in Central Appalachian surface mining. This workforce combined with CONSOL Energy’s underground mining expertise will allow us to build and transfer knowledge among operations to focus the best skill sets to development requirements of the various parts of this reserve block.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

The unaudited pro forma results, assuming the acquisition had occurred at January 1, 2007 are estimated to be:

 

		For the Year Ended December 31, 2007
Revenue		$	3,902,186
Earnings Before Taxes		$	444,409
Net Income		$	279,074
Basic Earnings Per Share		$	1.53
Dilutive Earnings Per Share		$	1.52

The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of 2007, nor are they necessarily indicative of future consolidated results.

In July 2007, CONSOL Energy completed the acquisition of Piping & Equipment, Inc. for a cash payment, net of cash acquired, of $16,914. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. Piping & Equipment, Inc. is a pipe, valve and fittings supplier with eight locations in Florida, Alabama, Louisiana and Texas. The fair value of merchandise for resale acquired in this acquisition is $8,481 and is included in inventory on the Consolidated Balance Sheets. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.

In June 2007, CONSOL Energy exchanged certain coal assets in Northern Appalachia with Peabody Energy for coalbed methane and gas rights. This transaction was accounted for as a non-monetary exchange under the Fair Value Measurements and Disclosures Topic of the Financial Accounting Standards Board Accounting Standards Codification resulting in a pre-tax gain of $50,060. Also in June 2007, CONSOL Energy, through a subsidiary, acquired certain coalbed methane and gas rights from Peabody Energy for a cash payment of $15,000 plus approximately $1,650 of various other acquisition costs.

In June 2007, CONSOL Energy sold the rights to certain western Kentucky coal in the Illinois Basin to Alliance Resource Partners, L.P. for $53,309. This transaction resulted in a pre-tax gain of $49,868.

Note 3—Other Income:

 

		For the Years Ended December 31,
		2009			2008			2007
Royalty income		$	17,249		$	20,673		$	14,205
Equity in earnings of affiliates			15,707			11,140			6,551
Gain on disposition of assets			15,121			23,368			112,389
Contract settlements			12,450			—			—
Service income			11,796			14,298			12,623
Interest income			5,052			2,363			12,792
Charter & tramp towing income			4,838			11,164			2,601
Buchanan roof collapse insurance proceeds			—			50,000			10,000
Other			30,973			33,136			25,567
Total Other Income		$	113,186		$	166,142		$	196,728

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Note 4—Interest Expense:

 

		For the Years Ended December 31,
		2009				2008				2007
Interest on debt		$	39,524			$	45,627			$	40,766
Interest on other payables			3,766				2,718				4,648
Interest capitalized			(11,871	)			(12,162	)			(14,563	)
Total Interest Expense		$	31,419			$	36,183			$	30,851

Note 5—Taxes Other Than Income:

 

		For the Years Ended December 31,
		2009				2008				2007
Production taxes		$	183,307			$	188,581			$	163,346
Payroll taxes			48,702				49,829				43,828
Property taxes			47,934				44,107				41,586
Capital stock & franchise tax			8,895				6,568				7,475
Virginia employment enhancement tax credit			(3,715	)			(4,190	)			(3,159	)
Other			4,818				5,095				5,850
Total Taxes Other Than Income		$	289,941			$	289,990			$	258,926

Note 6—Income Taxes:

Income taxes (benefits) provided on earnings consisted of:

 

		For the Years Ended December 31,
		2009				2008			2007
Current:
U.S. Federal		$	134,231			$	87,658		$	62,704
U.S. State			41,482				14,549			11,284
Non-U.S.			(1,940	)			2,133			2,594
			173,773				104,340			76,582
Deferred:
U.S. Federal			49,672				101,869			40,278
U.S. State			(2,242	)			33,725			19,277
			47,430				135,594			59,555
Total Income Taxes		$	221,203			$	239,934		$	136,137

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

The components of the net deferred tax assets are as follows:

 

		December 31,
		2009				2008
Deferred Tax Assets:
Postretirement benefits other than pensions		$	1,084,523			$	990,336
Mine closing			134,362				133,591
Alternative minimum tax			102,029				168,276
Pneumoconiosis benefits			81,724				75,124
Workers’ compensation			69,562				59,687
Salary retirement			68,820				74,967
Net operating loss			53,133				57,370
Capital lease			31,301				32,212
Reclamation			11,946				14,581
Other			120,911				78,923
Total Deferred Tax Assets			1,758,311				1,685,067
Valuation Allowance**			(61,623	)			(60,898	)
Net Deferred Tax Assets			1,696,688				1,624,169
Deferred Tax Liabilities:
Property, plant and equipment			(1,103,585	)			(1,085,054	)
Gas hedge			(46,129	)			(81,061	)
Advance mining royalties			(25,568	)			(23,445	)
Other			(22,726	)			(40,467	)
Total Deferred Tax Liabilities			(1,198,008	)			(1,230,027	)
Net Deferred Tax Assets		$	498,680			$	394,142

 

**	Valuation allowances of ($3,051) and ($58,572) have been allocated between current and long-term deferred tax assets respectively for 2009. Valuation allowances of ($2,663) and ($58,235) have been allocated between current and long-term deferred tax assets respectively for 2008.

A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. For the years ended December 31, 2009 and 2008, positive evidence considered included future income projections based on existing fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods.

In 2007, CONSOL Energy implemented a prudent and feasible tax strategy that ensured the realization of Pennsylvania loss carry forward tax benefits. For 2009 and 2008, CONSOL Energy continues to report a deferred tax asset of $16,081 and $22,656 on an after federal tax adjusted basis relating to the remainder of its state operating loss carry forwards after valuation allowances, respectively. A review of the positive and negative evidence regarding these tax benefits, primarily the history of financial and tax losses on a separate company basis, concluded that the valuation allowances were warranted. A valuation allowance of $24,571 and $26,184 on an after federal tax adjusted basis has also been recorded for 2009 and 2008 respectively, against the deferred state tax asset attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial and tax losses. The net operating loss carryforwards expire at various times between 2010 and 2027. Management will continue to assess the potential for realizing deferred tax assets based upon

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods as appropriate, that could materially impact net income. Included in the valuation allowance against the deferred state tax assets attributable to future deductible temporary differences for 2009 and 2008 are $7,952 and $8,496, respectively, of future tax benefits relating to other postretirement, pension and long-term disability benefits which are subject to a full valuation allowance. The decrease in the valuation allowances recognized related to other postretirement, pension and long-term disability benefits were recognized through Other Comprehensive Income in the applicable period.

We estimate that CONSOL Energy will utilize federal alternative minimum tax credits of $60,032 for the year ended December 31, 2009, thereby reducing the deferred tax asset associated with the prior years’ minimum tax credits. During 2009, the federal alternative minimum tax credits were increased $3,631 as a result of the 2008 accrual to 2008 return adjustments. As a result of the conclusion of the Internal Revenue Service (IRS) examination of the 2004 and 2005 tax returns, CONSOL Energy was able to utilize an additional $9,846 of alternative minimum tax credits.

The following is a reconciliation stated as a percentage of pretax income, of the United States statutory federal income tax rate to CONSOL Energy’s effective tax rate:

 

		For the Years Ended December 31,
		2009							2008							2007
		Amount				Percent			Amount				Percent			Amount				Percent
Statutory U.S. federal income tax rate		$	275,921			35.0	%		$	253,958			35.0	%		$	150,135			35.0	%
Excess tax depletion			(68,787	)		(8.7	)			(48,859	)		(6.7	)			(43,502	)		(10.1	)
Effect of Medicare Prescription Drug, Improvement and Modernization Act of 2003			2,112			0.3				2,112			0.3				1,796			0.4
Effect of domestic production activities			(12,707	)		(1.6	)			(7,721	)		(1.1	)			(915	)		(0.2	)
Net effect of state tax			25,377			3.2				31,169			4.3				20,086			4.7
Effect of foreign tax			(343	)		—				2,133			0.3				787			0.2
Other			(370	)		(0.1	)			7,142			1.0				7,750			1.7
Income Tax Expense/Effective Rate		$	221,203			28.1	%		$	239,934			33.1	%		$	136,137			31.7	%

A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:

 

		For the Years Ended December 31,
		2009				2008
Balance at beginning of period		$	84,554			$	91,696
Increase in unrecognized tax benefits resulting from tax positions taken during current period			17,461				11,725
Increase (decrease) in unrecognized tax benefits resulting from tax positions taken during prior period			7,825				(18,867	)
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations			(3,800	)			—
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities			(27,229	)			—
Balance at end of period		$	78,811			$	84,554

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

If these unrecognized tax benefits were recognized, $15,502 and $14,657 respectively would affect CONSOL Energy’s effective income tax rate.

CONSOL Energy and its subsidiaries file income tax returns in the U.S. federal, various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. During the year ended December 31, 2009, CONSOL Energy was advised by the Canadian Revenue Agency that its appeal of tax deficiencies paid as a result of the Agency’s audit of the Company’s Canadian tax returns filed for years 1997 through 2002 had been successfully resolved. The Company recorded a tax refund receivable of $4,560 as a result of the audit settlement.

During the year ended December 31, 2009, CONSOL Energy paid federal and state income tax deficiencies of $12,798 and $608, respectively. The federal and state deficiencies paid, as a result of the 2004 and 2005 tax returns, had an insignificant impact on net income due to the tax deficiencies being the result of changes in the timing of certain tax deductions.

The IRS is commencing its audit of CONSOL Energy’s income tax returns filed for 2006 and 2007. The Company expects to conclude this examination and remit payment of any resulting tax deficiencies to federal and state taxing authorities before December 31, 2010. Since the IRS examination is in its initial stages, any resulting tax deficiency or overpayment cannot be estimated at this time. During the next year the statute of limitations for assessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations for these years will have an insignificant impact on CONSOL Energy’s total uncertain income tax positions and net income for the twelve-month period.

CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2009 and 2008, the Company had an accrued liability of $8,338 and $10,518, respectively, for interest related to uncertain tax positions. The accrued interest liabilities include $2,409, $2,012 and $3,426 that were recorded in the Company’s Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007, respectively. During the year ended December 31, 2009, CONSOL Energy paid interest of $4,590 related to income tax deficiencies to the IRS as a result of its examinations of the Company’s tax returns filed for the years 2002 through 2005.

CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2009 and 2008, there were no accrued penalties recognized.

Note 7—Mine Closing, Reclamation & Gas Well Closing:

CONSOL Energy accrues for reclamation, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets, net of the associated accumulated depreciation. The obligation for asset retirements is included in Mine Closing, Reclamation, Gas Well Closing and Other Accrued Liabilities on the Consolidated Balance Sheets.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

The reconciliation of changes in the asset retirement obligations at December 31, 2009 and 2008 is as follows:

 

		As of December 31,
		2009				2008
Balance at beginning of period		$	544,314			$	530,897
Accretion expense			39,610				34,888
Payments			(31,458	)			(32,085	)
Revisions in estimated cash flows			(19,006	)			30,409
Other			(283	)			(19,795	)
Balance at end of period		$	533,177			$	544,314

For the year ended December 31, 2009, Other includes ($283) of various other items, none of which are individually significant. For the year ended December 31, 2008, Other includes ($19,618) for asset dispositions and ($177) of various other items, none of which are individually significant.

Note 8—Inventories:

Inventory components consist of the following:

 

		December 31,
		2009			2008
Coal		$	173,719		$	93,875
Merchandise for resale			44,842			43,074
Supplies			89,036			90,861
Total Inventories		$	307,597		$	227,810

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $13,696 and $14,716 at December 31, 2009 and 2008, respectively.

Note 9—Accounts Receivable Securitization:

CONSOL Energy and certain of our U.S subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. This facility allows CONSOL Energy to receive up to $165,000 on a revolving basis. The facility also allows for the issuance of letters of credit against the $165,000 capacity. At December 31, 2009, there were no letters of credit outstanding against the facility.

CONSOL Energy formed CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary for the sole purpose of buying and selling eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocable and without recourse, sell all of their eligible trade accounts receivable to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the pool of trade receivables. This retained interest, which is included in Accounts and Notes Receivable Trade in the Consolidated Balance Sheets, is recorded at fair value. Due to the short average collection cycle for the receivables that are part of this

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable reduced by the amount of accounts receivables sold to the third-party financial institutions under the program. CONSOL Energy will continue to service the trade receivables for the financial institutions for a fee based upon market rates for similar services.

The cost of funds under this facility is based upon commercial paper rates, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $2,990 and $5,814 for the year ended December 31, 2009 and 2008, respectively. These costs have been recorded as financing fees, which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in April 2012 with the underlying liquidity agreement renewing annually each April.

At December 31, 2009 and 2008, eligible accounts receivable totaled approximately $151,000 and $165,000, respectively. The subordinated retained interest approximated $101,000 at December 31, 2009. There was no subordinated retained interest at December 31, 2008. Accounts receivable totaling $50,000 and $165,000 were removed from the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. In accordance with the facility agreement, the company is able to receive proceeds based upon total eligible accounts receivable at the previous month end. CONSOL Energy’s $115,000 decrease and $39,600 increase in the accounts receivable securitization program for the years ended December 31, 2009 and 2008, respectively, is reflected in cash flows from operating activities in the Consolidated Statements of Cash Flows.

Note 10—Property, Plant and Equipment

 

		December 31,
		2009			2008
Coal and other plant and equipment		$	4,874,880		$	4,533,793
Coal properties and surface lands			1,284,795			1,264,920
Gas properties and related development			1,649,476			1,427,588
Gas gathering equipment			804,212			740,396
Airshafts			622,068			615,512
Leased coal lands			504,475			502,521
Mine development			573,037			527,991
Coal advance mining royalties			366,312			365,380
Gas advance royalties			2,700			2,187
Total Property, Plant and Equipment			10,681,955			9,980,288
Less—Accumulated depreciation, depletion and amortization			4,557,665			4,214,316
Net Property, Plant and Equipment		$	6,124,290		$	5,765,972

Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary greatly; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction, and are legally considered real property interests. We also make advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and we make payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. We evaluate our properties periodically for impairment issues or whenever events or circumstances indicate that the carrying amount may not be recoverable.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Coal reserves are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned or accessible to the mine. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is placed into production. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.

Amortization of capitalized mine development costs associated with a coal reserve is computed on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development costs begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Amortization of wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised whenever there is an indication of the need for a revision, but at least once a year, and accounted for prospectively.

Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted for prospectively as changes in accounting estimates.

The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yet commenced and therefore are not yet being amortized for the years ended December 31, 2009 and 2008, respectively.

 

		December 31,
		2009			2008
Coal properties and surface lands		$	393,368		$	395,880
Gas properties and related development			271,125			220,848
Airshafts			63,673			70,017
Leased coal lands			254,081			260,699
Mine development			114,800			98,842
Coal advance mining royalties			12,494			31,725
Gas advance royalties			2,405			2,187
Total		$	1,111,946		$	1,080,198

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

As of December 31, 2009 and 2008, plant and equipment includes gross assets under capital lease of $81,770 and $112,890, respectively. As of December 31, 2008, the Northern Appalachian coal segment maintained a $37,018 capital lease for longwall shields at Enlow Fork, which was included in Coal and other plant and equipment. In addition, for the years ended December 31, 2009 and 2008, the Gas segment maintains a capital lease for the Jewell Ridge Pipeline of $66,919, which is included in Gas gathering equipment. For the years ended December 31, 2009 and 2008, the Gas segment also maintains a capital lease for vehicles of $2,788 and $3,071, respectively, which are included in Gas properties and related development. For the years ended December 31, 2009 and 2008, the All Other segment maintains a capital lease for vehicles of $12,063 and $5,882, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $21,893 and $31,929 at December 31, 2009 and 2008, respectively. Amortization expense for capital leases is included in depreciation expense. See Note 14—Leases for additional capital lease details.

Note 11—Short-Term Notes Payable:

CONSOL Energy has a five-year $1,000,000 senior secured credit facility, which extends through June 2012. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. The Agreement does provide for the release of collateral at the request of CONSOL Energy upon achievement of certain credit ratings. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 4.50 to 1.00, measured quarterly. The interest coverage ratio was 24.78 to 1.00 at December 31, 2009. The facility also includes a maximum leverage ratio covenant of not more than 3.25 to 1.00, measured quarterly. The leverage ratio was 0.87 to 1.00 at December 31, 2009. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends and merge with another corporation. At December 31, 2009, the $1,000,000 facility had $415,000 of borrowings outstanding and $268,360 of letters of credit outstanding, leaving $316,640 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 0.86% and 1.71% as of December 31, 2009 and 2008, respectively.

CNX Gas has a five-year $200,000 unsecured credit agreement which extends through October 2010. The agreement contains a negative pledge provision, whereas CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. The leverage ratio was 0.38 to 1.00 at December 31, 2009. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 68.17 to 1.00 at December 31, 2009. At December 31, 2009, the CNX Gas credit agreement had $57,850 of borrowings outstanding and $14,913 of letters of credit outstanding, leaving $127,237 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 1.69% and 2.01% as of December 31, 2009 and 2008, respectively.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Note 12—Other Accrued Liabilities:

 

		December 31,
		2009			2008
Subsidence liability		$	72,390		$	54,013
Accrued payroll and benefits			50,696			59,765
Accrued other taxes			42,559			41,916
Uncertain income tax positions			42,423			28,903
Short-term incentive compensation			35,710			29,329
Royalties			24,098			33,857
Other			112,095			78,925
Current portion of long-term liabilities:
Postretirement benefits other than pensions			164,747			145,429
Workers’ compensation			27,885			32,778
Mine closing			19,568			16,833
Pneumoconiosis benefits			9,676			9,833
Reclamation			3,192			4,108
Long term disability			5,468			5,389
Salary retirement			2,331			2,034
Deferred revenue			—			3,330
Total Other Accrued Liabilities		$	612,838		$	546,442

Note 13—Long-Term Debt:

 

		December 31,
		2009			2008
Debt:
Secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $447 at December 31, 2009)		$	249,553		$	249,346
Baltimore Port Facility revenue bonds in series due December 2010 at 6.50%			30,865			30,865
Baltimore Port Facility revenue bonds in series due October 2011 at 6.50%			72,000			72,000
Advance royalty commitments			35,547			30,019
Notes due through 2011 at 6.10%			14,628			18,936
Other long-term notes maturing at various dates through 2031 (total value of $164 less unamortized discount of $4 at December 31, 2009)			160			1,121
			402,753			402,287
Less amounts due in one year			39,024			8,975
Total Long-Term Debt		$	363,729		$	393,312

Advance royalty commitments and the other long-term variable rate notes had a weighted average interest rate of approximately 7.36% at December 31, 2009 and 10.65% at December 31, 2008. The bonds and notes are carried net of debt discount, which is being amortized over the life of the issue.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Annual undiscounted maturities on long-term debt during the next five years are as follows:

 

Year Ended December 31,		Amount
2010		$	39,024
2011			85,344
2012			253,057
2013			2,847
2014			2,574
Thereafter			20,358
Total Long-Term Debt Maturities		$	403,204

Note 14—Leases:

CONSOL Energy uses various leased facilities and equipment in our operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2009, are as follows:

 

Year Ended December 31, 2009		Capital Leases			Operating Leases
2010		$	10,997		$	79,649
2011			9,977			73,012
2012			8,641			54,562
2013			7,718			51,044
2014			7,469			41,900
Thereafter			50,379			166,358
Total minimum lease payments		$	95,181		$	466,525
Less amount representing interest (0.63% - 7.36%)			29,632
Present value of minimum lease payments			65,549
Less amount due in one year			6,370
Total Long-Term Capital Lease Obligation		$	59,179

Rental expense under operating leases was $77,960, $63,170 and $47,765 for the years ended December 31, 2009, 2008 and 2007, respectively.

Note 15—Pension and Other Postretirement Benefit Plans:

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. The benefits for these plans are based primarily on years of service and employee’s pay near retirement.

The CONSOL Energy salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005 at the employees’ election. As of January 1, 2006, lump sum benefits have been frozen and prospectively the lump sum option has been eliminated. According to the Defined Benefit Plans Topic of the FASB Accounting Standards Codification, if the lump sum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the service cost and interest cost for the plan

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

year, settlement accounting is required. Lump sum payments did not exceed the threshold during 2009 or 2008. Lump sum payments exceeded this threshold during 2007. Accordingly, CONSOL Energy recognized expense of $2,734 for the year ended December 31, 2007 in the results of operations. The adjustment equaled the unrecognized actuarial loss resulting from each individual who received a lump sum in that year. CONSOL Energy regularly monitors this situation.

During the year ended December 31, 2009, certain former and existing CNX Gas employees became eligible to participate in the CONSOL Energy Supplemental Retirement Plan. The additional benefit liabilities for these employees have been reflected as Plan Amendments in the reconciliation of the changes in benefit obligation for the year ended December 31, 2009.

Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in CNX Gas’ non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit retirement plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.

Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. Prior to August 1, 2003, substantially all employees became eligible for these benefits if they had ten years of company service and attained age 55. Effective August 1, 2003, the base eligibility was changed to age 55 with 20 years of service for salaried employees. In addition, effective January 1, 2004, a medical plan cost sharing arrangement with all salaried employees and retirees was adopted. These participants will now contribute a target of 20% of the medical plan operating costs. Contributions may be higher, dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by CONSOL Energy and the participants. Annual cost increases in excess of 6% will be the sole responsibility of the participants. Also, any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007, or later, will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of two thousand two hundred and fifty dollars for each year of service at retirement. Newly employed inexperienced employees represented by the United Mine Workers of America, hired after January 1, 2007, will not be eligible to receive retiree benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.

CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of the adoption, the Company recognized an increase of $2,278 and $42,599 in the liabilities for pension and other postretirement benefits, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2009 and 2008, is as follows:

 

		Pension Benefits at December 31,								Other Benefits at December 31,
		2009				2008				2009				2008
Change in benefit obligation:
Benefit obligation at beginning of period		$	571,772			$	523,381			$	2,638,773			$	2,484,829
Contractual liability(a)			—				103				—				2,486
Service cost (9/30/07-12/31/07)			—				2,438				—				2,639
Service cost			12,332				9,752				12,654				10,554
Interest cost (9/30/07-12/31/07)			—				8,257				—				39,960
Interest cost			35,483				33,029				151,451				159,837
Actuarial loss			78,529				54,243				197,066				95,372
Plan amendments			3,371				49				—				22,456
Participant contributions (9/30/07-12/31/07)			—				—				—				1,221
Participant contributions			—				—				4,633				4,884
Benefits paid (9/30/07-12/31/07)			—				(12,536	)			—				(37,545	)
Benefits paid			(47,465	)			(46,944	)			(160,484	)			(147,920	)
Benefit obligation at end of period		$	654,022			$	571,772			$	2,844,093			$	2,638,773
Change in plan assets:
Fair value of plan assets at beginning of period		$	375,261			$	453,203			$	—			$	—
Actual return on plan assets			66,537				(60,256	)			—				—
Company contributions (9/30/07-12/31/07)			—				905				—				36,323
Company contributions			67,667				42,080				155,851				143,036
Participant contributions(9/30/07-12/31/07)			—				—				—				1,221
Participant contributions			—				—				4,633				4,884
Benefits and other payments (9/30/07-12/31/07)			—				(12,536	)			—				(37,544	)
Benefits and other payments			(47,465	)			(48,135	)			(160,484	)			(147,920	)
Fair value of plan assets at end of period		$	462,000			$	375,261			$	—			$	—
Funded status:
Noncurrent assets		$	6			$	90			$	—			$	—
Current liabilities			(2,331	)			(2,034	)			(164,747	)			(145,429	)
Noncurrent liabilities			(189,697	)			(194,567	)			(2,679,346	)			(2,493,344	)
Net obligation recognized		$	(192,022	)		$	(196,511	)		$	(2,844,093	)		$	(2,638,773	)
Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial loss		$	362,901			$	336,541			$	1,152,630			$	1,005,922
Prior service credit			(3,141	)			(7,621	)			(168,561	)			(214,976	)
Net amount recognized (before tax effect)		$	359,760			$	328,920			$	984,069			$	790,946

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

The components of net periodic benefit costs are as follows:

 

		Pension Benefits												Other Benefits
		For the Years Ended December 31,												For the Years Ended December 31,
		2009				2008				2007				2009				2008				2007
Components of net periodic benefit cost:
Service cost		$	12,332			$	9,752			$	11,015			$	12,654			$	10,555			$	10,988
Interest cost			35,483				33,029				28,710				151,451				159,837				139,221
Expected return on plan assets			(36,631	)			(33,671	)			(30,656	)			—				—				—
Settlement			—				—				2,734				—				—				—
Amortization of prior service cost (credit)			(1,109	)			(1,114	)			(1,114	)			(46,415	)			(48,625	)			(51,001	)
Recognized net actuarial loss			22,263				16,728				12,487				50,357				61,503				61,230
Benefit cost		$	32,338			$	24,724			$	23,176			$	168,047			$	183,270			$	160,438

Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:

 

		Pension Benefits				Postretirement Benefits
Prior service cost (benefit) recognition		$	(735	)		$	(46,415	)
Actuarial loss recognition		$	31,460			$	69,593

The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets:

 

		As of December 31,
		2009			2008
Projected benefit obligation		$	653,925		$	571,155
Accumulated benefit obligation		$	580,498		$	511,275
Fair value of plan assets		$	462,000		$	374,657

Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:

 

		Pension Benefits For the Year Ended December 31,						Other Benefits For the Year Ended December 31,
		2009			2008			2009			2008
Discount rate		5.79	%		6.28	%		5.87	%		6.20	%
Rate of compensation increase		4.09	%		4.05	%		—			—

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

The weighted-average assumptions used to determine net periodic benefit costs are as follows:

 

		Pension Benefits at December 31,									Other Benefits at December 31,
		2009			2008			2007			2009			2008			2007
Discount rate		6.28	%		6.57	%		6.00	%		6.20	%		6.63	%		6.00	%
Expected long-term return on plan assets		8.00	%		8.00	%		8.00	%		—			—			—
Rate of compensation increase		4.05	%		4.01	%		3.65	%		—			—			—

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:

 

		At December 31,
		2009			2008			2007
Health care cost trend rate for next year		8.74	%		9.60	%		8.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)		4.50	%		5.00	%		5.00	%
Year that the rate reaches ultimate trend rate		2023			2015			2013

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:

 

		1-Percentage Point Increase			1-Percentage Point Decrease
Effect on total of service and interest costs components		$	19,901		$	(17,043	)
Effect on accumulated postretirement benefit obligation		$	318,777		$	(276,481	)

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:

 

		0.25 Percentage Point Increase				0.25 Percentage Point Decrease
Pension benefit costs (decrease) increase		$	(750	)		$	740
Other postemployment benefits costs (decrease) increase		$	(3,833	)		$	3,779

Plan Assets:

The company’s overall investment strategy for its pension plan assets is to meet current and future benefit payment needs through diversification across asset classes, fund strategies and fund managers to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation. The target allocations for plan assets are 36 percent U.S. equity securities, 24 percent non-U.S.

 

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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 Global Investments (MGI) Common Collective Trusts. Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities being derived from both developed and emerging markets. Fixed income securities consist of U.S. as well as international instruments, including emerging markets. The core domestic fixed income portfolios invest in government, corporate, asset-backed securities and mortgage-backed obligations. The average quality of the fixed income portfolio must be rated at least “investment grade” by nationally recognized rating agencies. Within the fixed income asset class, investments are invested primarily across various strategies such that its overall profile strongly correlates with the interest rate sensitivity of the Trust’s liabilities in order to reduce the volatility resulting from the risk of changes in interest rates and the impact of such changes on the Trust’s overall financial status. Derivatives, interest rate swaps, options and futures are permitted investments for the purpose of reducing risk and to extend the duration of the overall fixed income portfolio; however, they may not be used for speculative purposes. All or a portion of the assets may be invested in mutual funds or other comingled vehicles so long as the pooled investment funds have an adequate asset base relative to their asset class; are invested in a diversified manner; and have management and/or oversight by an Investment Advisor registered with the Securities and Exchange Commission. The Retirement Board, as appointed by the CONSOL Energy Board of Directors, reviews the investment program on an ongoing basis including asset performance, current trends and developments in capital markets, changes in Trust liabilities and ongoing appropriateness of the overall investment policy.

The fair values of plan assets at December 31, 2009 by asset category are as follows:

 

		Fair Value Measurements at December 31, 2009
Asset Category		Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Cash		$	231		$	231		$	—		$	—
US Equities(a)			3			3			—			—
MGI Collective Trusts
US Large Cap Growth Equity(b)			42,186			—			42,186			—
US Large Cap Value Equity(c)			41,205			—			41,205			—
US Small/Mid Cap Growth Equity(d)			17,069			—			17,069			—
US Small/Mid Cap Value Equity(e)			16,826			—			16,826			—
US Core Fixed Income(f)			17,755			—			17,755			—
Non-US Core Equity(g)			110,747			—			110,747			—
US Long Duration Investment Grade Fixed Income(h)			41,261			—			41,261			—
US Long Duration Fixed Income(i)			58,466			—			58,466			—
US Large Cap Passive Equity(j)			52,255			—			52,255			—
US Passive Fixed Income(k)			12,999			—			12,999			—
US Long Duration Passive Fixed Income(l)			23,589			—			23,589			—
US Ultra Long Duration Fixed Income(m)			27,408			—			27,408			—
Total		$	462,000		$	234		$	461,766		$	—

 

(a)	This category includes investments in United States common stocks.

(b)

This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying

 

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risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.

(c)

This category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.

(d)

This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.

(e)

This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.

(f)

This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest in opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.

(g)

This category invests in all cap companies operating in developed and emerging markets outside the U.S. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.

(h)

This category invests in a passively managed U.S. long duration investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.

(i)

This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.

(j)	This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.

(k)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.

 

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(l)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.

(m)

This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.

There are no direct investments in CONSOL Energy stock held by these plans at December 31, 2009 or 2008.

There are no assets in the other postretirement benefit plans at December 31, 2009 or 2008.

Cash Flows:

CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $63,600 to our pension plan trust in 2010. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2010. We intend to pay benefit claims as they are due.

The following benefit payments, reflecting expected future service, are expected to be paid:

 

		Pension Benefits			Other Benefits
2010		$	38,212		$	164,747
2011		$	36,358		$	175,356
2012		$	44,017		$	182,548
2013		$	44,445		$	189,550
2014		$	47,684		$	196,119
Year 2015-2019		$	269,407		$	1,040,248

Note 16—Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation:

CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. CONSOL Energy primarily provides for these claims through a self-insurance program. The calculation of the actuarial present value of the estimated pneumoconiosis obligation is based on an annual actuarial study by independent actuaries. The calculation is based on assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates. These assumptions are derived from actual company experience and outside sources. Actuarial gains associated with CWP have resulted from numerous legislative changes over many years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed than our assumption originally reflected.

CONSOL Energy is also responsible to compensate individuals who sustain employment related physical injuries or some types of occupational diseases and, on some occasions, for costs of their rehabilitation. Workers’

 

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compensation laws will also compensate survivors of workers who suffer employment related deaths. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy primarily provides for these claims through a self-insurance program. CONSOL Energy recognizes an actuarial present value of the estimated workers’ compensation obligation calculated by independent actuaries. The calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions. The assumptions include discount rate, future health care trend rate, benefit duration and recurrence of injuries. Actuarial gains associated with workers’ compensation have resulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident rates than our assumptions.

CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of this adoption, the Company recognized an increase of $4,871 and $11,523 in liabilities for coal workers’ pneumoconiosis and workers’ compensation, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.

 

		CWP December 31,								Workers’ Compensation December 31,
		2009				2008				2009				2008
Change in benefit obligation:
Benefit obligation at beginning of period		$	200,094			$	182,872			$	159,761			$	162,060
Contractual liability(a)			—				1,689				—				355
State administrative fees and insurance bond premiums			—				—				6,710				5,509
Service cost (9/30-12/31)			—				1,934				—				7,257
Service cost			9,774				7,736				31,795				29,030
Interest cost (9/30-12/31)			—				2,937				—				2,082
Interest cost			12,054				11,748				8,765				8,328
Actuarial (gain) loss			(16,584	)			4,117				9,825				(4,236	)
Benefits paid (9/30-12/31)			—				(1,455	)			—				(11,834	)
Benefits paid			(10,697	)			(11,484	)			(37,588	)			(38,790	)
Benefit obligation at end of period		$	194,641			$	200,094			$	179,268			$	159,761
Current liabilities		$	(9,676	)		$	(9,833	)		$	(27,885	)		$	(32,778	)
Noncurrent liabilities			(184,965	)			(190,261	)			(151,383	)			(126,983	)
Net obligation recognized		$	(194,641	)		$	(200,094	)		$	(179,268	)		$	(159,761	)
Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain		$	(184,666	)		$	(187,672	)		$	(45,232	)		$	(59,257	)
Prior service credit			(1,851	)			(2,579	)			—				—
Net amount recognized (before tax effect)		$	(186,517	)		$	(190,251	)		$	(45,232	)		$	(59,257	)

 

(a)	Amounts offset by a contractual receivable included in Other Assets on the Consolidated Balance Sheets.

 

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The components of the net periodic cost (credit) are as follows:

 

		CWP For the Years Ended December 31,												Workers’ Compensation For the Years Ended December 31,
		2009				2008				2007				2009				2008				2007
Components of Net Periodic Cost (Credit):
Service cost		$	7,074			$	5,036			$	5,856			$	28,394			$	29,030			$	29,659
Interest cost			12,054				11,748				11,401				8,765				8,328				8,356
Legal and administrative costs			2,700				2,700				2,700				3,401				3,224				3,259
Amortization of prior service cost			(728	)			(728	)			(728	)			—				—				—
Recognized net actuarial gain			(19,590	)			(23,383	)			(22,371	)			(4,200	)			(4,938	)			(3,953	)
State administrative fees and insurance bond premiums			—				—				—				6,710				5,509				10,591
Net periodic cost (credit)		$	1,510			$	(4,627	)		$	(3,142	)		$	43,070			$	41,153			$	47,912

Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:

 

		CWP Benefits				Workers’ Compensation Benefits
Prior service benefit recognition		$	(728	)		$	—
Actuarial gain recognition		$	(19,196	)		$	(3,072	)

Assumptions:

The weighted-average discount rate used to determine benefit obligations and net periodic (benefit) cost are as follows:

 

		CWP For Years Ended December 31,									Workers’ Compensation For Years Ended December 31,
		2009			2008			2007			2009			2008			2007
Benefit obligations		5.84	%		6.23	%		6.62	%		5.55	%		5.90	%		5.94	%
Net Periodic (benefit) costs		6.23	%		6.62	%		6.00	%		5.90	%		5.94	%		6.00	%

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:

 

		0.25 Percentage Point Increase				0.25 Percentage Point Decrease
CWP benefit (decrease) increase		$	(655	)		$	643
Workers’ Compensation costs (decrease) increase		$	(29	)		$	23

 

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Cash Flows:

CONSOL Energy does not intend to make contributions to the CWP or Workers’ Compensation plans in 2010. We intend to pay benefit claims as they become due.

The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:

 

					Workers’ Compensation
		CWP Benefits			Total Benefits			Actuarial Benefits			Other Benefits
2010		$	9,676		$	34,359		$	27,885		$	6,474
2011		$	10,217		$	35,989		$	29,256		$	6,733
2012		$	10,791		$	37,365		$	30,363		$	7,002
2013		$	11,351		$	38,507		$	31,225		$	7,282
2014		$	11,885		$	39,437		$	31,863		$	7,574
Year 2015-2019		$	65,428		$	204,744		$	162,081		$	42,663

Note 17—Other Employee Benefit Plans:

UMWA Pension and Benefit Trusts:

Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan negotiated with the United Mine Workers of America (the UMWA) and contained in the National Bituminous Coal Wage Agreement (the NBCWA). The NBCWA currently calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The current contribution rates called for by the NBCWA are: $4.25 per hour worked in 2009, $5.00 per hour worked in 2010 and $5.50 per hour worked in 2011. Total contributions for a year may differ from total expenses for the year due to the timing of actual contributions compared to the date of assessment. Total contributions to the UMWA 1974 Pension Trust were $25,620, $21,140 and $11,354 for the years ended December 31, 2009, 2008 and 2007, respectively. These multi-employer pension plan contributions are expensed as incurred. The Pension Protection Act requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan and if the plan is determined to have a funded ratio of less than 80% it will be deemed to be “endangered” or "seriously endangered", and if less than 65%, it will be deemed to be in “critical” status, and will in either case be subject to additional funding requirements. Under the Pension Act, the multi-employer plan's actuary must certify the plan's funded status for each plan year. Based on an estimated funded percentage of 91.4%, a certification was provided by the multi-employer plan actuary, stating that the 1974 Pension Trust was in neither “endangered” nor “critical” status for the plan year beginning July 1, 2008. However, the volatile economic environment and the recent rapid deterioration in the equity markets caused investment income and the value of investment assets held in the 1974 Pension Trust to decline and lose value.

In late 2008, the Worker, Retiree and Employer Recovery Act of 2008 (“WRERA”) was enacted. Under WRERA, a plan is permitted temporarily to avoid applying the Pension Act's requirements for improving its financial status by giving a plan the option to elect to retain its prior year zone status and to freeze the plan's zone status at the level determined for 2008. WRERA also required that the plan's actuary certify the plan's actual zone status for 2009. On September 28, 2009, based on an estimated funded percentage of 74%, the 1974 Pension Trust's actuary provided the Pension Act zone certification for 2009, certifying that the 1974 Pension Trust is “seriously endangered” for the plan year beginning July 1, 2009. Thereafter, pursuant to WRERA, the 1974 Pension Trust elected to retain its 2008 funded status of neither “endangered” nor “critical” for the plan year

 

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beginning July 1, 2009. If the freeze election had not been made, the 1974 Pension Trust's zone status for 2009 as certified by its actuary would have been “seriously endangered” and the 1974 Pension Trust would have been required to develop a funding improvement plan.

The freeze election only applies for the 2009 plan year. If the 1974 Pension Trust is certified to be endangered, seriously endangered or in critical status for the plan year beginning July 1, 2010, steps will have to be taken under the Pension Act to improve its funded status. Such a determination would require certain subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results.

The Coal Industry Retiree Health Benefit Act of 1992 (the Act) created two multi-employer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund (the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the 1992 Benefit Fund. CONSOL Energy subsidiaries account for required contributions to these multi-employer trusts as expense when incurred.

The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefits as of July 20, 1992. The 1992 Benefit Fund provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Act. The Act requires that responsibility for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost is recognized when contributions are assessed. Total contributions under the Act were $22,646, $24,343 and $32,916 for the years ended December 31, 2009, 2008 and 2007, respectively. Costs were reduced in 2007 by $30,389 due to the March 2007 settlement agreement with the Combined Fund that resolved all previous issues relating to the calculation of payments to the Combined Fund. See Note 24—Commitments and Contingencies in Notes to Audited Financial Statements for additional details on the settlement agreement. Based on available information at December 31, 2009, CONSOL Energy’s obligation for the Act is estimated at approximately $182,084.

The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the NBCWA of 1993. This plan provides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the 1992 Benefit Fund, or whose last employer signed the 1993 or a later NBCWA and who subsequently goes out of business. Contributions to the trust under the 2007 agreement are $1.44 per hour worked by UMWA represented employees for the year ended December 31, 2009, comprised of a $0.50 per hour worked under the labor agreement and $0.94 per hour worked by UMWA represented employees under the Tax Relief and Health Care Act of 2006 (the 2006 Act). Contributions to the trust under the 2007 agreement are $1.77 per hour worked by UMWA represented employees for the year ended December 31, 2008, comprised of a $0.50 per hour worked under the labor agreement and $1.27 per hour worked by UMWA represented employees under the 2006 Act. The contribution rate for the year ended December 31, 2007, was $2.00 per hour worked by UMWA represented employees, comprised of $0.50 per hour worked under the labor agreement and $1.50 per hour worked under the 2006 Act. Total contributions were $9,072, $11,494 and $11,627 for the years ended December 31, 2009, 2008 and 2007, respectively.

Pursuant to the provisions of the 2006 Act and the 1992 Plan, CONSOL Energy is required to provide security in an amount based on the annual cost of providing health care benefits for all individuals receiving benefits from the 1992 Plan who are attributable to CONSOL Energy, plus all individuals receiving benefits from

 

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an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with the 2006 Act and the 1992 Plan, the outstanding letters of credit to secure our obligation were $61,734 and $60,695 for years ended December 31, 2009 and 2008, respectively. The 2009 and 2008 security amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible employees.

At December 31, 2009, approximately 34.5% of CONSOL Energy’s workforce was represented by the UMWA.

Equity Incentive Plans:

CONSOL Energy has an equity incentive plan that provides grants of stock-based awards to key employees and to non-employee directors. See Note 18 for a further discussion of CONSOL Energy’s stock-based compensation.

The CNX Gas equity incentive plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, performance share units, cash awards and other stock-based awards. The total number of shares of CNX Gas common stock with respect to which awards may be granted under CNX Gas’ plan is 2,500,000. CNX Gas stock-based compensation expense, excluding allocated portions from CONSOL Energy resulted in pre-tax expense of $6,311, $3,379 and $3,260 to CONSOL Energy for the years ended December 31, 2009, 2008 and 2007, respectively.

Long Term Incentive Compensation:

CNX Gas had a long-term incentive program. This program allowed for the award of performance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of the Company’s common stock. The total number of units earned, if any, by a participant was based on the Company’s total stock holder return relative to the stock holder return of a pre-determined peer group of companies. CNX Gas recognized compensation costs over the requisite service period. The basis of the compensation costs was re-valued quarterly. Approximately $8,779 and $2,231 of compensation costs have been recognized for the years ended December 31, 2008 and 2007, respectively. A credit to expense of approximately $1,434 was recognized for the year ended December 31, 2009 as a result of the decline in the value of the expected payout prior to the exchange transaction discussed below.

During the second quarter of 2009, CNX Gas recognized the effect of an exchange offer that allowed participants in the CNX Gas Long-Term Incentive Program to exchange their unvested performance share units for CONSOL Energy restricted stock units. The excess fair value of the replacement restricted stock units over the original performance stock units resulted in $2,738 of incremental restricted stock compensation expense being immediately recognized. Additionally, a liability of $10,347 for the cash settlement of the CNX Gas performance share units was reclassified into equity due to the issuance of RSUs. As a result of the completed exchange offer there are no outstanding performance share units at December 31, 2009.

Investment Plan:

CONSOL Energy has an investment plan available to all domestic, non-represented employees. Effective January 1, 2006, the company match was 6% of base pay for all non-represented employees except for those employees of Fairmont Supply Company whose match remains at 50% of the first 12% of base pay. In

 

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addition, effective January 1, 2007, the definition of eligible compensation for employee deferrals and company match was amended to include overtime for all non-represented employees except for those employees of Fairmont Supply Company whose definition of eligible compensation will remain unchanged. CNX Gas employees hired on or after January 1, 2007 also receive an additional 3% non-elective contribution in lieu of participation in the CNX Gas pension plan. Total payments and costs were $24,353, $23,091 and $17,896 for the years ended December 31, 2009, 2008 and 2007, respectively.

Long-Term Disability:

CONSOL Energy has a Long-Term Disability Plan available to all full-time salaried employees. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.

 

		For The Years Ended December 31,
		2009				2008				2007
Benefit Costs		$	3,642			$	3,998			$	3,050
Discount rate assumption used to determine net periodic benefit obligations			5.92	%			5.92	%			5.99	%

Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities—Other and Other Accrued Liabilities and amounted to $30,097 and $29,645 for the years ended December 31, 2009 and 2008, respectively.

Note 18—Stock-Based Compensation:

CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan on April 7, 1999. The plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the plan have been approved by the Board of Directors since the commencement of the plan. In 2009, the Board of Directors approved an increase in the total number of shares by 5,600,000 bringing the total number of shares of common stock that can be covered by grants at December 31, 2009 to 23,800,000 of which 2,600,000 are available for issuance of awards other than stock options. The Plan, as amended, will provide that the aggregate number of shares available for issuance under the Plan will be reduced by one share for each share issued in settlement of Performance Share Units (PSUs) or Restricted Stock Units (RSUs) and by 1.44 for any other award. No award of stock options may be exercised under the plan after the tenth anniversary of the effective date of the award.

In accordance with the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy recognizes stock-based compensation costs net of an estimated forfeiture rate and recognizes the compensation costs for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term, or to an employee’s eligible retirement date, if earlier and applicable. The total stock-based compensation expense recognized was $32,723, $21,807 and $20,983 for the years ended December 31, 2009, 2008 and 2007, respectively. The related deferred tax benefit totaled $12,490, $8,293 and $7,938, for the years ended December 31, 2009, 2008 and 2007, respectively.

CONSOL Energy examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based on certain employee populations. From this analysis, CONSOL Energy identified two distinct employee populations. CONSOL Energy used the Black-Scholes option pricing model to value the options for each of the employee populations. The table below presents the weighted average expected term in years of the two employee populations. The expected term computation is based upon historical

 

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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, 2009, 2008 and 2007 were $9,950, $11,395 and $9,912, respectively. The fair value of share-based payment awards was estimated using the Black-Scholes option pricing model with the following assumptions and weighted average fair values:

 

		December 31,
		2009				2008				2007
Weighted average fair value of grants		$	14.48			$	29.44			$	11.93
Risk-free interest rate			1.45	%			2.59	%			4.70	%
Expected dividend yield			1.40	%			0.50	%			0.80	%
Expected forfeiture rate			2.00	%			2.00	%			2.00	%
Expected volatility			75.60	%			46.60	%			38.20	%
Expected term in years			4.10 years				3.97 years				4.07 years

A summary of the status of stock options granted is presented below:

 

		Shares			Weighted Average Exercise Price			Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)
Balance at December 31, 2008		4,894,864			$	26.40
Granted		687,117			$	27.89
Exercised		(167,424	)		$	15.55
Forfeited		(27,416	)		$	39.89
Balance at December 31, 2009		5,387,141			$	26.86		5.46		$	134,166
Vested and expected to vest		5,339,497			$	26.72		5.50		$	133,573
Exercisable at December 31, 2009		4,024,879			$	26.80		4.59		$	114,105

These stock options will terminate ten years after the date on which they were granted. The employee stock options, covered by the Equity Incentive Plan adopted April 7, 1999, vest 25% per year, beginning one year after the grant date for awards granted prior to 2007. Employee stock options awarded after December 31, 2006 vest 33% per year, beginning one year after the grant date. There are 4,848,213 stock options outstanding under the Equity Incentive plan. Additionally, there are 446,180 fully vested employee stock options outstanding which had vesting terms ranging from six months to one year. Non-employee director stock options vest 33% per year, beginning one year after the grant date. There are 92,747 stock options outstanding under these grants. The vesting of all options will accelerate in the event of death, disability or retirement and may accelerate upon a change in control of CONSOL Energy. In 2008, the compensation committee of the board of directors changed the retirement eligible acceleration of vesting to require a minimum vesting period of twelve months. This change is effective for all stock based compensation awards issued after January 1, 2008.

The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CONSOL Energy’s closing stock price on the last trading day of the year ended December 31, 2009, and

 

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the option’s exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2009. This amount varies based on the fair market value of CONSOL Energy’s stock. Total intrinsic value of options exercised for the year ended December 31, 2009, 2008 and 2007 was $4,502, $55,131 and $65,294, respectively.

Cash received from option exercises for the years ended December 31, 2009, 2008 and 2007 was $2,547, $15,215 and $19,224, respectively. The excess tax benefit realized for the tax deduction from option exercises totaled $3,270, $22,003 and $23,682 for the years ended December 31, 2009, 2008 and 2007, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.

Under the Equity Incentive Plan, CONSOL Energy granted certain employees and non-employee directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. Compensation expense will be recognized over the vesting period of the units. The total fair value of the restricted stock units granted during the years ended December 31, 2009, 2008 and 2007 were $42,720, $5,950 and $6,373, respectively. The total fair value of shares vested during the years ended December 31, 2009, 2008 and 2007 was $18,092, $4,720 and $3,641, respectively. The following represents the unvested restricted stock units and corresponding fair value (based upon the closing share price) at the date of grant:

 

		Number of Shares			Weighted Average Grant Date Fair Value
Nonvested at December 31, 2008		389,296			$	42.57
Granted		1,489,538			$	28.68
Vested		(553,701	)		$	32.68
Forfeited		(30,756	)		$	28.85
Nonvested at December 31, 2009		1,294,377			$	31.15

Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance share unit awards. These awards entitle the holder to receive shares of common stock subject to the achievement of certain market and performance goals. Compensation expense will be recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. At December 31, 2009, achievement of the market and performance goals is believed to be probable. The total fair value of performance share units granted during the years ended December 31, 2009, 2008 and 2007 were $5,684, $4,904 and $3,237. The following represents the unvested performance share unit awards and their corresponding fair value (based upon the closing share price) at the date of grant:

 

		Number of Shares		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2008		126,877		$	64.16
Granted		164,186		$	34.62
Nonvested at December 31, 2009		291,063		$	47.50

As of December 31, 2009, $24,570 of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.57 years. When employee stock options are exercised and restricted and performance share unit awards become vested, the issuances are made from CONSOL Energy’s treasury stock shares which have been acquired as part of CONSOL Energy’s share repurchase program as previously discussed in Note 1.

 

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Note 19—Accumulated Other Comprehensive Loss:

Components of accumulated other comprehensive loss consists of the following:

 

		Treasury Rate Lock				Change in Fair Value of Cash Flow Hedges				Adjustments for Actuarially Determined Liabilities				Adjustments for Non- controlling Interest				Accumulated Other Comprehensive Loss
Balance at December 31, 2006		$	421			$	1,346			$	(377,484	)		$	—			$	(375,717	)
Net increase in value of cash flow hedges			—				23,943				—				(4,370	)			19,573
Reclassification of cash flow hedges from other comprehensive income to earnings			—				(19,729	)			—				3,601				(16,128	)
Current period change			(81	)			—				(47,009	)			78				(47,012	)
Balance at December 31, 2007			340				5,560				(424,493	)			(691	)			(419,284	)
Net increase in value of cash flow hedges			—				117,699				—				(20,646	)			97,053
Reclassification of cash flow hedges from other comprehensive income to earnings			—				947				—				(166	)			781
Current period change			(77	)			—				(140,305	)			19				(140,363	)
Prior period adjustment			—				—				(87	)			—				(87	)
Balance at December 31, 2008			263				124,206				(564,885	)			(21,484	)			(461,900	)
Net increase in value of cash flow hedges			—				186,824				—				(31,162	)			155,662
Reclassification of cash flow hedges from other comprehensive income to earnings			—				(239,956	)			—				40,024				(199,932	)
Current period change			(83	)			—				(134,549	)			298				(134,334	)
Balance at December 31, 2009		$	180			$	71,074			$	(699,434	)		$	(12,324	)		$	(640,504	)

The cash flow hedges that CONSOL Energy holds are disclosed in Note 23. The adjustments for Actuarially Determined Liabilities are disclosed in Note 15 and Note 16.

 

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Note 20—Supplemental Cash Flow Information:

 

		For the Years Ended December 31,
		2009				2008				2007
Cash paid during the year for:
Interest (net of amounts capitalized)		$	26,425			$	33,236			$	26,415
Income taxes		$	131,043			$	95,101			$	103,194
Non-cash investing and financing activities:
Adoption of Accounting for Uncertainty in Income Taxes
Change in Assets		$	—			$	—			$	(39,207	)
Change in Liabilities		$	—			$	—			$	(39,207	)
Businesses acquired (Note 2)
Fair value of assets acquired		$	28,113			$	(26,892	)		$	(132,694	)
Liabilities assumed		$	28,113			$	(26,892	)		$	(132,694	)
Note received from property sales		$	(1,789	)		$	—			$	(200	)
Capital Lease Obligation
Change in Assets		$	(3,375	)		$	2,622			$	(1,083	)
Change in Liabilities		$	(3,375	)		$	2,622			$	(1,083	)
Purchase of Property, Plant and Equipment
Change in Assets		$	46,938			$	(75,818	)		$	3,219
Change in Liabilities		$	46,938			$	(75,818	)		$	3,219
Accounting for Mine Closing, Reclamation and Gas Well Closing Costs
Change in Assets		$	283			$	(29,088	)		$	3,403
Change in Liabilities		$	283			$	(29,088	)		$	3,403

Note 21—Concentration of Credit Risk and Major Customers:

CONSOL Energy markets steam coal, principally to electric utilities in the United States, Canada and Western Europe, metallurgical coal to steel and coke producers worldwide, and natural gas primarily to gas wholesalers. As of December 31, 2009 and 2008, accounts receivable from utilities were $215,743 and $222,808, respectively. As of December 31, 2009 and 2008, accounts receivable from steel and coke producers were $43,448 and $40,788, respectively. As of December 31, 2009 and 2008, accounts receivable from gas wholesalers were $43,421 and $61,764, respectively. Credit is extended based on an evaluation of the customer’s financial condition, and generally collateral is not required. Credit losses have been consistently minimal.

For the years ended December 31, 2009, 2008 and 2007, no customer comprised over 10% of our revenues.

Note 22—Fair Values of Financial Instruments:

Effective January 1, 2008, CONSOL Energy adopted the provision for Fair Value of Financial Assets and Financial Liabilities as required by the Financial Accounting Standards Board Accounting Standards Codification. As a result of the adoption, CONSOL Energy elected not to measure any additional financial assets or liabilities at fair value, other than those which were previously recorded at fair value prior to the adoption.

 

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The financial instruments measured at fair value on a recurring basis are summarized below:

 

		Fair Value Measurements at December 31, 2009
Description		Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges		$	—		$	117,483		$	—

The following methods and assumptions were used to estimate the fair values of financial instruments, which the fair value option was not elected:

Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to the short maturity of these instruments.

Short-term notes payable: The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

 

		December 31, 2009								December 31, 2008
		Carrying Amount				Fair Value				Carrying Amount				Fair Value
Cash and cash equivalents		$	65,607			$	65,607			$	138,512			$	138,512
Short-term notes payable		$	(472,850	)		$	(472,850	)		$	(557,700	)		$	(557,700	)
Long-term debt		$	(402,753	)		$	(420,056	)		$	(402,287	)		$	(390,278	)

Note 23—Derivative Instruments:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. Our derivatives are accounted for under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification. We measure each derivative instrument at fair value and record it on the balance sheet as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in Other Comprehensive Income or Loss (OCI) and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

CONSOL Energy formally assesses both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in the fair values or the cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.

 

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CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. All of the counterparties to CONSOL Energy’s natural gas derivative instruments also participate in CONSOL Energy’s revolving credit facility. The Company has not experienced any issues of non-performance by derivative counterparties.

CONSOL Energy has entered into forward and option contracts on various commodities to manage the price risk associated with the forecasted revenues from those commodities. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodities.

As of December 31, 2009, the total notional amount of the Company’s outstanding natural gas forward contracts was 85.1 billion cubic feet. These forward contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $60,307 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

As of December 31, 2009, CONSOL Energy did not have any outstanding coal sales options. For the years ended December 31, 2009 and 2008, CONSOL Energy recognized, in Other Income on the Consolidated Statement of Income, a gain of $2,368 and a loss of ($335), respectively, for the coal sales options which were not designated as hedging instruments.

The fair value of CONSOL Energy’s derivative instruments at December 31, 2009 is as follows:

 

		Derivatives As of December 31, 2009
		Balance Sheet Location		Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps		Prepaid Expense		$	99,265
Natural Gas Price Swaps		Other Assets			18,218
Total derivatives designated as hedging instruments				$	117,483

The effect of derivative instruments on the Consolidated Statement of Income for the year ended December 31, 2009 is as follows:

 

Derivative in Cash Flow Hedging Relationship		Amount of Gain(Loss) Recognized in OCI on Derivative 2009				Location of Gain (Loss) Reclassified from Accumulated OCI into Income		Amount of Gain (Loss) Reclassified from Accumulated OCI into Income 2009			Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative 2009
Natural Gas Price Swaps		$	(185,862	)		Outside Sales		$	239,956		Outside Sales		$	(962	)
Total		$	(185,862	)				$	239,956				$	(962	)

 

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The fair value of CONSOL Energy’s derivative instruments at December 31, 2008 is as follows:

 

		Asset Derivatives 2008					Liability Derivatives 2008
		Balance Sheet Location		Fair Value			Balance Sheet Location		Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps		Prepaid Expense		$	150,564
		Other Assets			55,945
Total derivatives designated as hedging instruments				$	206,509				$	—
Derivative not designated as hedging instruments
Coal Sales Options					—		Other Liabilities			(1,937	)
Total derivatives not designated as hedging instruments				$	—				$	(1,937	)
Total Derivatives				$	206,509				$	(1,937	)

The effect of derivative instruments on the consolidated statement of income for the year ended December 31, 2008 is as follows:

 

Derivative in Cash Flow Hedging Relationship		Amount of Gain(Loss) Recognized in OCI on Derivative 2008				Location of Gain (Loss) Reclassified from Accumulated OCI into Income		Amount of Gain (Loss) Reclassified from Accumulated OCI into Income 2008				Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative 2008
Natural Gas Price Swaps		$	(118,652	)		Outside Sales		$	(947	)		Outside Sales		$	952
Total		$	(118,652	)				$	(947	)				$	952

Note 24—Commitments and Contingent Liabilities:

CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. Our current estimates related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2008, the Pennsylvania Department of Conservation and Natural Resources (Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company’s underground longwall mining activities caused cracks and seepage damage to the Ryerson Park Dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resources damages totaling $58,000. The Court stayed the proceedings in the state court, holding that the Commonwealth should pursue administrative agency review of the claim. Furthermore, the Court found that the Commonwealth could not recover natural resources damages under applicable law. The issue of whether the dam was damaged by subsidence is being reviewed by the

 

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Department of Environmental Protection (DEP). If the DEP determines that there is causation, a second phase will be set to determine the remedy. As to the underlying claim, the Company believes it is not responsible for the damage to the dam and that numerous grounds exist upon which to attack the propriety of the claims. The Company intends to vigorously defend the case. However, it is reasonably possible that the ultimate liability in the future with respect to these claims may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Past payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOL Energy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.

CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. At that time, the EPA also identified 38 other PRPs for the Ward Transformer site. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. Another party joined the participating PRPs and reduced CONSOL Energy’s interim allocation share from 46% to 32%. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties.

The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $55,000. The current estimated cost of the most likely remediation plan for one of the additional areas discovered is approximately $10,000, although the removal action plan is not yet approved by the EPA. Also, in September 2008, the EPA notified CONSOL Energy and 60 other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. There was $3,422, $7,080 and $1,780 of expense recognized in Cost of Goods Sold and Other Charges for the years ended December 31, 2009, 2008 and 2007, respectively. CONSOL Energy funded $5,500, $6,000 and $1,256 in the years ended December 31, 2009, 2008 and 2007, respectively, to an independent trust established for this remediation. The remaining liability at December 31, 2009 of $5,914 is reflected in Other Accrued Liabilities at December 31, 2009.

As of April 30, 2009, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claims against approximately 225 nonparticipating PRPs to recover a share of the costs

 

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incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy’s portion of probable recoveries from settled claims is estimated to be $3,620. Accordingly, an asset has been included in Other Assets for these claims. We cannot predict the ultimate outcome of this Superfund site; however, it is reasonably possible that payments in the future with respect to this lawsuit may be material to the financial position, results of operations or cash flows of CONSOL Energy.

As part of conducting mining activities at the Buchanan Mine, our subsidiary, Consolidation Coal Company (“CCC”), has to remove water from the mine. Several actions have arisen with respect to the removal of naturally accumulating and pumped water from the Buchanan Mine:

Yukon Pocahontas Coal Company, Buchanan Coal Company and Sayers-Pocahontas Coal Company filed an action on March 22, 2004 against CCC which is presently pending in the Circuit Court of Buchanan County, Virginia (the “Yukon Action”). The action is related to CCC’s depositing of untreated water from its Buchanan Mine into the void spaces of nearby mines of one of our other subsidiaries, Island Creek Coal Company (“ICCC”). The plaintiffs are seeking to stop CCC from depositing any additional water in these areas, to require CCC to remove the water that is stored there along with any remaining impurities, to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs have also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. The Yukon group has recently filed a demand for arbitration (the “2008 Arbitration”) against ICCC which makes similar claims relating to breach of the lease for water deposits and lost coal claims.

CCC obtained a revision to its environmental permit to deposit water from its Buchanan Mine into void spaces of VP3, and to permit the discharge of water into the nearby Levisa River under controlled conditions. Plaintiffs in the Yukon Action along with the Town of Grundy, Virginia, Buchanan County Board of Supervisors, and others have appealed the revision.

We believe that CCC has and continues to have the right to deposit mine water from Buchanan Mine into void spaces at nearby mines. We also believe CCC was properly issued environmental permits to deposit water from the Buchanan Mine into VP3 and to discharge water into the Levisa River. CCC and the other named CONSOL Energy defendants in the Yukon Action deny all liability and intend to vigorously defend the action filed against them in connection with the removal and deposit of water from the Buchanan Mine, as well as environmental permits issued to CCC. Consequently, we have not recognized any liability related to these actions. However, if a temporary or permanent injunction were to be issued against CCC, if the environmental permits were temporarily suspended or revoked, or if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2006, CONSOL Energy and CCC were served with a summons in the name of the Commonwealth of Virginia with the Circuit Court of Buchanan County, Virginia regarding a special grand jury presentment in response to citizens’ complaints that noise resulting from the ventilation fan at the Buchanan Mine constitutes a public nuisance. CONSOL Energy and CCC deny that the operation of the ventilation fan is a public nuisance and intend to vigorously defend this proceeding. However, if the operation of the ventilation fan is ordered to be stopped, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In, 2007 Bluestone Coal Corporation filed a lawsuit against the Company and its subsidiary, CNX Land Resources, in the United States District Court for the Southern District of West Virginia. The suit alleges that the Company breached a contract that allegedly provides Bluestone with an option to lease coal reserves within a seven-and-one-half mile radius of Bishop, WV and seeks damages of $1,200,000. The writing relied upon only

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

refers to a right of first refusal, rather than an option. The lawsuit has been settled. The terms of the settlement are confidential, but include CONSOL Energy granting to Bluestone the option to acquire certain mining assets and reserves. The settlement did not materially impact the financial position, results of operations or cash flows of CONSOL Energy.

South Carolina Electric & Gas Company (“SCE&G”), a utility, has demanded arbitration, seeking $36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. The Company counterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement which SCE&G had agreed could be made up in 2009. A hearing on the claims is scheduled for October 11, 2010. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them. However, if damages were awarded to SCE&G, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden brown algae in the creek, which appears to be an invasive species. Our subsidiary, CCC, discharges treated mine water into Dunkard Creek from its Blacksville No. 2 Mine and from its Loveridge Mine. The discharges have levels of chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection that sets forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the West Virginia Department of Environmental Protection issued a unilateral Order that imposes additional conditions on CCC's discharges into Dunkard Creek and requires CCC to develop a plan for long-term treatment of those and other high-chloride discharges. The Dunkard Creek fish kill is being investigated by several agencies, including the West Virginia Department of Environmental Protection, the West Virginia Department of Natural Resources, the Pennsylvania Department of Environmental Protection, and the Pennsylvania Fish and Boat Commission. The U.S. Environmental Protection Agency is also involved. We are cooperating with these investigations. We do not believe that there is a connection between the fish kill and our discharge of water into Dunkard Creek, but the investigation of the matter is continuing. If such a causal connection were established or if we are required to comply with in-stream chloride limits on an accelerated basis, it is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to these matters may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

In 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CONSOL Energy and certain of its affiliates, including CNX Gas Company LLC, in the Circuit Court for the County of Tazewell, Virginia. The lawsuit alleges, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, seeks injunctive relief, compensatory damages of $385,600 and treble damages. CNX Gas continues to believe this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.

In 2009, CNX Gas received a civil investigative demand for information and documents from the Attorney General of the Commonwealth of Virginia regarding the company's exploration, production, transportation and sale of coalbed methane gas in Virginia. According to the request, the Attorney General is investigating whether the company may have violated the Virginia Antitrust Act. The request for information does not constitute the commencement of legal proceedings and does not make any specific allegations against the company. CNX Gas does not believe that it has violated the Virginia Antitrust Act and CNX Gas is cooperating with the Attorney General's investigation.

 

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The Company is a party to a case filed in 2007 captioned Earl Kennedy (and others) v. CNX Gas and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas. The complaint, as amended, seeks injunctive relief, including having CNX Gas be removed from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.

In 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a lawsuit against CNX Gas Company LLC in the Circuit Court of the County of Buchanan for the year 2002; the county has since filed and served three substantially similar cases for years 2003, 2004 and 2005. These cases have been consolidated. The complaint alleges that CNX Gas’ calculation of the license tax on the basis of the wellhead value (sales price less post production costs) rather than the sales price is improper. For the period from 1999 through mid 2002, CNX Gas paid the tax on the basis of the sales price, but we have filed a claim for a refund for these years. Since 2002, we have continued to pay Buchanan County taxes based on our method of calculating the taxes. This litigation has been settled on terms that do not materially impact the financial position or the results of operations of CNX Gas or CONSOL Energy.

In 2007, the assigned operators, including subsidiaries of CONSOL Energy, and the Combined Fund entered into a settlement agreement that resolved all issues relating to the calculation and imposition of higher per beneficiary premium rates. The settlement agreement provides for full reimbursement of the higher per beneficiary premium rate. The settlement agreement provided for full reimbursement of higher per beneficiary premium rate previously paid by CONSOL Energy subsidiaries and related interest. In the year ended December 31, 2007, CONSOL Energy received $30,389 which was reflected as a reduction to cost of goods sold and other charges.

In 2007, production at the Buchanan Mine was suspended after several roof falls damaged some of the ventilation controls inside the mine. Production resumed in March 2008. The incident was covered under our property and business interruption insurance policy, subject to certain deductibles. Business interruption recoveries of $50,000 were recognized as Other Income in the year ended December 31, 2008, $42,000 in the coal segment and $8,000 in the gas segment.

In 2008, the Emergency Economic Stabilization Act of 2008 (the EESA Act) was signed into law. The EESA Act contained a section that authorizes certain coal producers and exporters who had filed a Black Lung Excise Tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales during these years. The EESA Act requires that the U.S. Treasury refund a coal producer or exporter an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. In the year ended December 31, 2008, CONSOL Energy recognized a receivable related to these refunds of $58,983, including interest of $32,444. In relation to this receivable, CONSOL Energy recognized a payable of $3,187 that was owed to third parties upon collection of the refunds. The receivable was collected and the related payables were paid in the year ended December 31, 2009.

 

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At December 31, 2009, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credits are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.

 

		Amount and Duration of Commitments
		Total Amounts Committed			Less Than 1 Year			1-3 Years			3-5 Years			Beyond 5 Years
Letters of Credit:
Employee-Related		$	193,017		$	193,017		$	—		$	—		$	—
Environmental			63,502			63,502			—			—			—
Gas			14,913			14,913			—			—			—
Other			11,914			11,850			64			—			—
Total Letters of Credit			283,346			283,282			64			—			—
Surety Bonds:
Employee-Related			193,251			193,251			—			—			—
Environmental			345,955			345,782			173			—			—
Gas			4,442			4,442			—			—			—
Other			9,726			9,713			13			—			—
Total Surety Bonds			553,374			553,188			186			—			—
Guarantees:
Coal			111,088			79,890			25,198			1,000			5,000
Gas			56,156			30,479			22,577			—			3,100
Other			277,694			42,925			71,617			51,991			111,161
Total Guarantees			444,938			153,294			119,392			52,991			119,261
Total Commitments		$	1,281,658		$	989,764		$	119,642		$	52,991		$	119,261

CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2009, the purchase obligations for each of the next five years were as follows:

 

Obligations Due		Amount
Less than 1 year		$	69,228
1 – 3 years			55,680
3 – 5 years			49,934
More than 5 years			303,347
Total Purchase Obligations		$	478,189

 

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Costs related to major equipment purchases under these purchase obligations was $89,261, $10,957 and $15,886 for the years ended December 31, 2009, 2008 and 2007. Firm transportation expense under these purchase obligations was $21,668, $11,476 and $9,390 for the years ended December 31, 2009, 2008 and 2007 respectively. Expenses related to gas drilling purchase obligations were $585 for the year ended December 31, 2009. Expenses related to other operating goods and services under these purchase obligations was $120 and $60 for the years ended December 31, 2009 and 2008.

Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Gas financial guarantees have primarily been provided to support various performance bonds related to land usage and restorative issues. Other guarantees have been extended to support insurance policies, legal matters and various other items necessary in the normal course of business. Other guarantees have also been provided to promise the full and timely payments to lessors of mining equipment and support various other items necessary in the normal course of business.

Note 25—Segment Information:

CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal unit includes four reportable segments. These reportable segments are Northern Appalachian, Central Appalachian, Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines). For the year ended December 31, 2009, the Northern Appalachian aggregated segment includes the following mines: Blacksville #2, Robinson Run, McElroy, Loveridge, Bailey, Enlow Fork, Mine 84 and Shoemaker. For the year ended December 31, 2009, the Central Appalachian aggregated segment includes the following mines: Jones Fork Complex, the Miller Creek Complex, the Fola Complex and the Terry Eagle Complex. For the year ended December 31, 2009, the Metallurgical aggregated segment includes the following mines: Buchanan and Amonate Complex. The Other Coal segment includes our purchased coal activities, idled mine cost, coal segment business units not meeting aggregation criteria, as well as various other activities assigned to the coal segment but not allocated to each individual mine. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities, including rentals of buildings and flight operations. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Certain reclassifications of 2008 and 2007 segment information have been made to conform to the 2009 presentation.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Industry segment results for the year ended December 31, 2009 are:

 

		Northern Appalachian			Central Appalachian			Metallurgical			Other Coal				Total Coal			Gas			All Other			Corporate, Adjustments & Eliminations				Consolidated
Sales—outside		$	2,545,779		$	460,973		$	248,543		$	154,591			$	3,409,886		$	628,929		$	272,976		$	—			$	4,311,791	(A)
Sales—Purchased Gas			—			—			—			—				—			7,040			—			—				7,040
Sales—Gas Royalty Interests			—			—			—			—				—			40,951			—			—				40,951
Freight—outside			—			—			—			148,907				148,907			—			—			—				148,907
Intersegment transfers			—			—			—			—				—			1,671			152,375			(154,046	)			—
Total Sales and Freight		$	2,545,779		$	460,973		$	248,543		$	303,498			$	3,558,793		$	678,591		$	425,351		$	(154,046	)		$	4,508,689
Earnings (Loss) Before Income Taxes		$	666,476		$	30,401		$	74,689		$	(155,764	)		$	615,802		$	261,835		$	9,983		$	(99,275	)		$	788,345	(B)
Segment assets															$	4,672,508		$	2,171,495		$	317,004		$	564,394			$	7,725,401	(C)
Depreciation, depletion and amortization															$	310,346		$	107,251		$	19,820		$	—			$	437,417
Capital expenditures															$	580,401		$	322,126		$	17,553		$	—			$	920,080

 

(A)	There were no sales to customers aggregating over 10% of total revenue in 2009.

(B)	Includes equity in earnings of unconsolidated affiliates of $5,663, $637 and $9,408 for Coal, Gas and All Other, respectively.

(C)	Includes investments in unconsolidated equity affiliates of $12,569, $24,590 and $46,374 for Coal, Gas and All Other, respectively.

 

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(Dollars in thousands, except per share data)

Industry segment results for the year ended December 31, 2008 are:

 

		Northern Appalachian			Central Appalachian				Metallurgical			Other Coal				Total Coal			Gas			All Other			Corporate, Adjustments & Eliminations				Consolidated
Sales—outside		$	2,126,182		$	519,428			$	341,177		$	197,657			$	3,184,444		$	680,990		$	316,135		$	—			$	4,181,569	(D)
Sales—Purchased Gas			—			—				—			—				—			8,464			—			—				8,464
Sales—Gas Royalty Interests			—			—				—			—				—			79,302			—			—				79,302
Freight—outside			—			—				—			216,968				216,968			—			—			—				216,968
Intersegment transfers			—			—				—			—				—			7,337			145,856			(153,193	)			—
Total Sales and Freight		$	2,126,182		$	519,428			$	341,177		$	414,625			$	3,401,412		$	776,093		$	461,991		$	(153,193	)		$	4,486,303
Earnings (Loss) Before Income Taxes		$	323,348		$	(18,040	)		$	190,331		$	(88,601	)		$	407,038		$	385,954		$	18,526		$	(85,923	)		$	725,595	(E)
Segment assets																$	4,387,584		$	2,094,748		$	322,137		$	565,989			$	7,370,458	(F)
Depreciation, depletion and amortization																$	299,831		$	70,010		$	19,780		$	—			$	389,621
Capital expenditures																$	445,594		$	560,663		$	55,412		$	—			$	1,061,669

 

(D)	There were no sales to customers aggregating over 10% of total revenue in 2008.

(E)	Includes equity in earnings of unconsolidated affiliates of $2,534, $551 and $8,055 for Coal, Gas and All Other, respectively.

(F)	Includes investments in unconsolidated equity affiliates of $9,386, $25,204 and $38,406 for Coal, Gas and All Other, respectively. Also, included in the Coal segment is $58,983 of receivables related to the Emergency Economic Stabilization Act of 2008.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Industry segment results for the year ended December 31, 2007 are:

 

		Northern Appalachian			Central Appalachian			Metallurgical			Other Coal				Total Coal			Gas			All Other			Corporate, Adjustments & Eliminations				Consolidated
Sales—outside		$	1,990,897		$	383,596		$	237,266		$	66,922			$	2,678,681		$	410,211		$	235,454		$	—			$	3,324,346	(G)
Sales—Purchased Gas			—			—			—			—				—			7,628			—			—				7,628
Sales—Gas Royalty Interests			—			—			—			—				—			46,586			—			—				46,586
Freight—outside			—			—			—			186,909				186,909			—			—			—				186,909
Intersegment transfers			—			—			—			—				—			6,242			129,648			(135,890	)			—
Total Sales and Freight		$	1,990,897		$	383,596		$	237,266		$	253,831			$	2,865,590		$	470,667		$	365,102		$	(135,890	)		$	3,565,469
Earnings (Loss) Before Income Taxes		$	353,104		$	32,451		$	65,080		$	(173,128	)		$	277,507		$	214,874		$	15,152		$	(78,576	)		$	428,957	(H)
Segment assets															$	4,039,513		$	1,378,709		$	253,792		$	536,076			$	6,208,090	(I)
Depreciation, depletion and amortization															$	257,349		$	48,961		$	18,405		$	—			$	324,715
Capital expenditures															$	681,408		$	304,088		$	54,342		$	—			$	1,039,838

 

(G)	There were no sales to customers aggregating over 10% in 2007.

(H)	Includes equity in earnings of unconsolidated affiliates of $1,027, $2,174 and $3,350 for Coal, Gas and All Other, respectively.

(I)	Includes investments in unconsolidated equity affiliates of $3,101, $56,865 and $34,900 for Coal, Gas and All Other, respectively.

 

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Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Income:

 

		For the Years Ended December 31,
		2009				2008				2007
Total segment sales and freight from external customers		$	4,508,689			$	4,486,303			$	3,565,469
Other income not allocated to segments (Note 3)			113,186				166,142				196,728
Total Consolidated Revenue and Other Income		$	4,621,875			$	4,652,445			$	3,762,197
Earnings Before Income Taxes:
Segment Earnings Before Income Taxes for total reportable business segments		$	877,637			$	792,992			$	492,381
Segment Earnings (Loss) Before Income Taxes for all other businesses			9,983				18,526				15,152
Incentive compensation(J)			(35,071	)			(24,872	)			(26,770	)
Compensation from restricted stock unit grants, stock option expense and performance share unit expense(J)			(26,686	)			(21,807	)			(20,983	)
Interest income (expense), net and other non-operating activity(J)			(26,472	)			(39,244	)			(30,823	)
Corporate restructuring(J)			(4,378	)			—				—
Lease settlement(J)			(6,668	)			—				—
Earnings Before Income Taxes		$	788,345			$	725,595			$	428,957
		December 31,
		2009				2008				2007
Total Assets:
Segment assets for total reportable business segments		$	6,844,003			$	6,482,332			$	5,418,222
Segment assets for all other businesses			317,004				322,137				253,792
Items excluded from segment assets:
Cash and other investments(J)			65,025				136,951				9,978
Deferred tax assets			498,680				394,142				505,631
Recoverable income taxes			—				33,862				19,090
Bond issuance costs			689				1,034				1,377
Total Consolidated Assets		$	7,725,401			$	7,370,458			$	6,208,090

 

(J)	Excludes amounts specifically related to the gas segment.

 

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(Dollars in thousands, except per share data)

 

Enterprise-Wide Disclosures:

CONSOL Energy’s Revenues by geographical location:

 

		For the Years Ended December 31,
		2009			2008			2007
United States		$	4,026,619		$	3,841,665		$	3,077,573
Europe			298,262			462,291			332,280
South America			120,174			94,230			40,255
Canada			25,056			88,106			115,361
Other			38,578			11
Total Revenues and Freight from External Customers(K)		$	4,508,689		$	4,486,303		$	3,565,469

 

(K)	CONSOL Energy attributes revenue to individual countries based on the location of the customer.

CONSOL Energy’s Property, Plant and Equipment by geographical location are:

 

		December 31,
		2009			2008
United States		$	6,090,703		$	5,732,021
Canada			33,587			33,828
Belgium			—			123
		$	6,124,290		$	5,765,972

Note 26—Guarantor Subsidiaries Financial Information:

The payment obligations under the $250,000, 7.875 percent per annum notes due March 1, 2012 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by several subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (“SEC”), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, an 83.3% owned guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. CNX Gas is presented in a separate column in accordance with SEC Regulation S-X Rule 3-10. CNX Gas Corporation is a reporting company under Section 12(b) of the Securities Exchange Act of 1933, and as such, CNX Gas Corporation files its own financial statements with the Securities and Exchange Commission and those financial statements, when filed, are publicly available on Edgar. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other 100% owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

 

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(Dollars in thousands, except per share data)

 

Income Statement for the Year Ended December 31, 2009:

 

		Parent				CNX Gas Guarantor			Other Subsidiary Guarantors				Non-Guarantors			Elimination				Consolidated
Sales—Outside		$	—			$	630,598		$	3,487,022			$	197,350		$	(3,179	)		$	4,311,791
Sales—Purchased gas			—				7,040			—				—			—				7,040
Sales—Gas Royalty Interest			—				40,951			—				—			—				40,951
Freight—Outside			—				—			148,907				—			—				148,907
Other Income (including equity earnings)			622,216				4,855			76,442				22,173			(612,500	)			113,186
Total Revenue and Other Income			622,216				683,444			3,712,371				219,523			(615,679	)			4,621,875
Cost of Goods Sold and Other Operating Charges			84,960				155,583			2,083,462				190,854			242,193				2,757,052
Purchased Gas Costs			—				6,442			—				—			—				6,442
Gas Royalty Interest			—				32,423			—				—			(47	)			32,376
Related Party Activity			7,052				—			132,106				1,495			(140,653	)			—
Freight Expense			—				—			148,907				—			—				148,907
Selling, General and Administrative Expense			—				99,526			118,287				1,287			(88,396	)			130,704
Depreciation, Depletion and Amortization			13,022				107,251			316,352				2,654			(1,862	)			437,417
Interest Expense			13,229				7,568			10,959				15			(352	)			31,419
Taxes Other Than Income			9,576				12,590			265,180				2,595			—				289,941
Black Lung Excise Tax Refund			—				—			(728	)			—			—				(728	)
Total Costs			127,839				421,383			3,074,525				198,900			10,883				3,833,530
Earnings (Loss) Before Income Taxes			494,377				262,061			637,846				20,623			(626,562	)			788,345
Income Taxes (Benefit)			(45,340	)			98,636			160,105				7,802			—				221,203
Net Income			539,717				163,425			477,741				12,821			(626,562	)			567,142
Less: Net Income Attributable to Noncontrolling Interest			—				1,037			(1,037	)			—			(27,425	)			(27,425	)
Net Income Attributable to CONSOL Energy Inc. Shareholders		$	539,717			$	164,462		$	476,704			$	12,821		$	(653,987	)		$	539,717

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Balance Sheet for December 31, 2009:

 

		Parent			CNX Gas Guarantor				Other Subsidiary Guarantors				Non-Guarantors			Elimination				Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents		$	59,549		$	1,124			$	3,764			$	1,170		$	—			$	65,607
Accounts and Notes Receivable:
Trade			—			43,421				113				273,926			—				317,460
Other			4,781			975				3,281				6,946			—				15,983
Inventories			—			—				262,755				44,842			—				307,597
Deferred Income Taxes			108,254			(34,871	)			—				—			—				73,383
Prepaid Expenses			18,979			103,094				36,767				2,166			—				161,006
Total Current Assets			191,563			113,743				306,680				329,050			—				941,036
Property, Plant and Equipment:
Property, Plant and Equipment			162,145			2,409,751				8,082,159				27,900			—				10,681,955
Less-Accumulated Depreciation, Depletion and Amortization			82,733			433,201				4,022,295				19,436			—				4,557,665
Property, Plant and Equipment—Net			79,412			1,976,550				4,059,864				8,464			—				6,124,290
Other Assets:
Deferred Income Taxes			759,790			(334,493	)			—				—			—				425,297
Investment in Affiliates			4,399,823			24,591				797,269				3,921			(5,142,071	)			83,533
Other			84,736			21,627				33,216				11,666			—				151,245
Total Other Assets			5,244,349			(288,275	)			830,485				15,587			(5,142,071	)			660,075
Total Assets		$	5,515,324		$	1,802,018			$	5,197,029			$	353,101		$	(5,142,071	)		$	7,725,401
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable		$	93,876		$	53,516			$	114,872			$	7,296		$	—			$	269,560
Accounts Payable (Recoverable)-Related Parties			2,117,616			5,171				(2,378,119	)			255,332			—				—
Short-Term Notes Payable			415,000			57,850				—				—			—				472,850
Current Portion of Long-Term Debt			501			8,616				35,853				424			—				45,394
Accrued Income Taxes			27,944			31,765				(31,765	)			—			—				27,944
Other Accrued Liabilities			546,066			25,455				34,569				6,748			—				612,838
Total Current Liabilities			3,201,003			182,373				(2,224,590	)			269,800			—				1,428,586
Long-Term Debt:			250,255			65,690				106,369				594			—				422,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions			—			3,642				2,675,704				—			—				2,679,346
Pneumoconiosis			—			—				184,965				—			—				184,965
Mine Closing			—			—				397,320				—			—				397,320
Gas Well Closing			—			8,312				77,680				—			—				85,992
Workers’ Compensation			—			—				152,486				—			—				152,486
Deferred Revenue			—			—				—				—			—				—
Salary Retirement			189,697			—				—				—			—				189,697
Reclamation			—			—				27,105				—			—				27,105
Other			88,821			35,101				8,595				—			—				132,517
Total Deferred Credits and Other Liabilities			278,518			47,055				3,523,855				—			—				3,849,428
Consol Energy Inc. Stockholders’ Equity			1,785,548			1,511,270				3,787,025				82,707			(5,381,002	)			1,785,548
Noncontrolling Interest			—			(4,370	)			4,370				—			238,931				238,931
Total Liabilities and Stockholders’ Equity		$	5,515,324		$	1,802,018			$	5,197,029			$	353,101		$	(5,142,071	)		$	7,725,401

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Condensed Statement of Cash Flows

For the Year Ended December 31, 2009:

 

		Parent				CNX Gas Guarantor				Other Subsidiary Guarantors				Non-Guarantors				Elimination			Consolidated
Net Cash Provided by Operating Activities		$	64,095			$	360,163			$	523,596			$	(2,403	)		$	—		$	45,451
Cash Flows from Investing Activities:
Capital Expenditures		$	—			$	(336,447	)		$	(583,633	)		$	—			$	—		$	(920,080	)
Investment in Equity Affiliates			—				1,250				3,605				—				—			4,855
Proceeds from Sale of Assets			—				288				69,596				—				—			69,884
Net Cash Used in Investing Activities		$	—			$	(334,909	)		$	(510,432	)		$	—			$	—		$	(845,341	)
Cash Flows from Financial Activities:
Dividends Paid		$	(72,292	)		$	—			$	—			$	—			$	—		$	(72,292	)
Proceeds from Revolver			(70,000	)			(14,850	)			—				—				—			(84,850	)
Other Financing Activities			5,275				(11,206	)			(9,481	)			(461	)			—			(15,873	)
Net Cash Provided By (Used in) Financing Activities		$	(137,017	)		$	(26,056	)		$	(9,481	)		$	(461	)		$	—		$	(173,015	)

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Income Statement for the Year Ended December 31, 2008:

 

		Parent				CNX Gas Guarantor			Other Subsidiary Guarantors				Non-Guarantors			Elimination				Consolidated
Sales—Outside		$	—			$	688,325		$	3,231,163			$	271,613		$	(9,532	)		$	4,181,569
Sales—Purchased gas			—				8,464			—				—			—				8,464
Sales—Gas Royalty Interest			—				79,302			—				—			—				79,302
Freight—Outside			—				—			216,968				—			—				216,968
Other Income (including equity earnings)			513,910				13,330			117,487				38,375			(516,960	)			166,142
Total Revenue and Other Income			513,910				789,421			3,565,618				309,988			(526,492	)			4,652,445
Cost of Goods Sold and Other Operating Charges			72,790				132,254			2,312,477				112,402			213,280				2,843,203
Purchased Gas Costs			—				8,175			—				—			—				8,175
Gas Royalty Interest			—				74,041			—				—			(79	)			73,962
Related Party Activity			5,622				—			39,325				155,304			(200,251	)			—
Freight Expense			—				—			216,968				—			—				216,968
Selling, General and Administrative Expense			—				80,246			39,660				4,637			—				124,543
Depreciation, Depletion and Amortization			9,382				70,010			300,635				11,485			(1,891	)			389,621
Interest Expense			17,888				7,820			10,312				498			(335	)			36,183
Taxes Other Than Income			5,887				24,146			250,398				9,559			—				289,990
Black Lung Excise Tax Refund			—				—			(55,795	)			—			—				(55,795	)
Total Costs			111,569				396,692			3,113,980				293,885			10,724				3,926,850
Earnings (Loss) Before Income Taxes			402,341				392,729			451,638				16,103			(537,216	)			725,595
Income Taxes (Benefit)			(40,129	)			153,656			120,315				6,092			—				239,934
Net Income			442,470				239,073			331,323				10,011			(537,216	)			485,661
Less: Net Income Attributable to Noncontrolling Interest			—				—			—				—			(43,191	)			(43,191	)
Net Income Attributable to CONSOL Energy Inc. Shareholders		$	442,470			$	239,073		$	331,323			$	10,011		$	(580,407	)		$	442,470

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Balance Sheet for December 31, 2008:

 

		Parent			CNX Gas Guarantor				Other Subsidiary Guarantors				Non-Guarantors			Elimination				Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents		$	132,471		$	1,926			$	81			$	4,034		$	—			$	138,512
Accounts and Notes Receivable:
Trade			—			61,764				35				159,930			—				221,729
Other			1,767			3,080				68,910				5,795			—				79,552
Inventories			—							184,140				43,670			—				227,810
Recoverable Income Taxes			3,560			30,302				—											33,862
Deferred Income Taxes			115,599			(55,000	)			—				—			—				60,599
Prepaid Expenses			23,612			152,786				40,409				4,943			—				221,750
Total Current Assets			277,009			194,858				293,575				218,372			—				983,814
Property, Plant and Equipment:
Property, Plant and Equipment			175,027			2,113,570				7,606,735				84,956			—				9,980,288
Less-Accumulated Depreciation, Depletion and Amortization			71,781			322,470				3,793,378				26,687			—				4,214,316
Property, Plant and Equipment—Net			103,246			1,791,100				3,813,357				58,269			—				5,765,972
Other Assets:
Deferred Income Taxes			664,881			(331,338	)			—				—			—				333,543
Investment in Affiliates			3,734,125			25,204				930,708				1,102			(4,618,143	)			72,996
Other			77,253			58,811				34,521				43,548			—				214,133
Total Other Assets			4,476,259			(247,323	)			965,229				44,650			(4,618,143	)			620,672
Total Assets		$	4,856,514		$	1,738,635			$	5,072,161			$	321,291		$	(4,618,143	)		$	7,370,458
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable		$	87,734		$	100,565			$	159,677			$	37,221		$	—			$	385,197
Accounts Payable (Recoverable)- Related Parties			1,853,629			2,234				(1,992,924	)			137,061			—				—
Short-Term Notes Payable			485,000			72,700				—				—			—				557,700
Current Portion of Long-Term Debt			1,473			8,462				12,093				373			—				22,401
Other Accrued Liabilities			410,086			42,089				84,417				9,850			—				546,442
Total Current Liabilities			2,837,922			226,050				(1,736,737	)			184,505			—				1,511,740
Long-Term Debt:			252,145			74,682				140,956				568			—				468,351
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions			—			2,728				2,490,616				—			—				2,493,344
Pneumoconiosis			—			—				190,261				—			—				190,261
Mine Closing			—			—				393,112				11,517			—				404,629
Gas Well Closing			—			7,401				73,153				—			—				80,554
Workers’ Compensation			—			—				128,477				—			—				128,477
Salary Retirement			194,567			—				—				—			—				194,567
Reclamation			—			—				15,363				22,830			—				38,193
Other			109,693			42,900				7,698				25,705			—				185,996
Total Deferred Credits and Other Liabilities			304,260			53,029				3,298,680				60,052			—				3,716,021
CONSOL Energy Inc. Stockholders’ Equity			1,462,187			1,384,874				3,370,895				74,533			(4,830,302	)			1,462,187
Noncontrolling Interest			—			—				—				—			212,159				212,159
Total Liabilities and Stockholders’ Equity		$	4,856,514		$	1,738,635			$	5,073,794			$	319,658		$	(4,618,143	)		$	7,370,458

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Condensed Statement of Cash Flows

For the Year Ended December 31, 2008:

 

		Parent				CNX Gas Guarantor				Other Subsidiary Guarantors				Non-Guarantors				Elimination			Consolidated
Net Cash Provided by Operating Activities		$	34,647			$	447,375			$	510,475			$	36,967			$	—		$	1,029,464
Cash Flows from Investing
Capital Expenditures		$	(11,371	)		$	(560,663	)		$	(464,603	)		$	(25,032	)		$	—		$	(1,061,669	)
Investment in Equity Affiliates			—				1,081				798				—				—			1,879
Purchase of Stock in Subsidiary											(67,259	)										(67,259	)
Proceeds from Sale of Assets			—				450				27,743				—				—			28,193
Net Cash Used in Investing Activities		$	(11,371	)		$	(559,132	)		$	(503,321	)		$	(25,032	)		$	—		$	(1,098,856	)
Cash Flows from Financing Activities:
Dividends Paid		$	(72,957	)		$	—			$	—			$	—			$	—		$	(72,957	)
Proceeds from Revolver			237,500				72,700				—				—				—			310,200
Purchase of Treasury Stock			(97,794	)			—				—				—				—			(97,794	)
Other Financing Activities			37,218				8,935				(8,364	)			(10,985	)			—			26,804
Net Cash Provided By (Used in) Financing Activities		$	103,967			$	81,635			$	(8,364	)		$	(10,985	)		$	—		$	166,253

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Income Statement for the Year Ended December 31, 2007:

 

		Parent				CNX Gas Guarantor			Other Subsidiary Guarantors				Non-Guarantors			Elimination				Consolidated
Sales—Outside		$	—			$	416,453		$	2,718,493			$	201,018		$	(11,618	)		$	3,324,346
Sales—Purchased gas			—				7,628			—				—			—				7,628
Sales—Gas Royalty Interest			—				46,586			—				—			—				46,586
Freight—Outside			—				—			186,909				—			—				186,909
Other Income (including equity earnings)			333,581				8,815			141,735				40,093			(327,496	)			196,728
Total Revenue and Other Income			333,581				479,482			3,047,137				241,111			(339,114	)			3,762,197
Cost of Goods Sold and Other Operating Charges			63,899				102,278			1,916,159				61,864			207,800				2,352,000
Purchased Gas Costs			—				7,162			—				—			—				7,162
Gas Royalty Interest			—				40,011			—				—			(90	)			39,921
Related Party Activity			(4,601	)			—			87,459				134,213			(217,071	)			—
Freight Expense			—				—			186,909				—			—				186,909
Selling, General and Administrative Expense			—				54,825			51,029				2,810			—				108,664
Depreciation, Depletion and Amortization			7,666				48,961			259,825				10,343			(2,080	)			324,715
Interest Expense			24,932				5,606			(250	)			563			—				30,851
Taxes Other Than Income			5,790				—			246,177				6,959			—				258,926
Black Lung Excise Tax Refund			—				—			24,092				—			—				24,092
Total Costs			97,686				258,843			2,771,400				216,752			(11,441	)			3,333,240
Earnings (Loss) Before Income Taxes			235,895				220,639			275,737				24,359			(327,673	)			428,957
Income Taxes (Benefit)			(31,887	)			84,961			73,848				9,215			—				136,137
Net Income			267,782				135,678			201,889				15,144			(327,673	)			292,820
Less: Net Income Attributable to Noncontrolling Interest			—				—			—				—			(25,038	)			(25,038	)
Net Income Attributable to CONSOL Energy Inc. Shareholders		$	267,782			$	135,678		$	201,889			$	15,144		$	(352,711	)		$	267,782

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Condensed Statement of Cash Flows

For the Year Ended December 31, 2007:

 

		Parent				CNX Gas Guarantor				Other Subsidiary Guarantors				Non-Guarantors				Elimination			Consolidated
Net Cash Provided by Operating Activities		$	(258,800	)		$	272,448			$	649,136			$	21,249			$	—		$	684,033
Cash Flows from Investing Activities:
Capital Expenditures		$	—			$	(348,631	)		$	(372,424	)		$	(22,059	)		$	—		$	(743,114	)
Acquisition of AMVEST			—				—				(296,724	)			—				—			(296,724	)
Investment in Equity Affiliates			—				(5,783	)			(1,274	)			—				—			(7,057	)
Purchase of Stock in Subsidiary			—				—				(10,000	)			—				—			(10,000	)
Proceeds from Sale of Assets			—				187				83,754				850				—			84,791
Net Cash Used in Investing Activities		$	—			$	(354,227	)		$	(596,668	)		$	(21,209	)		$	—		$	(972,104	)
Cash Flows from Financing Activities:
Dividends Paid		$	(56,475	)		$	—			$	—			$	—			$	—		$	(56,475	)
Proceeds from Revolver			247,500				—				—				—				—			247,500
Purchase of Treasury Stock			(80,157	)			—				—				—				—			(80,157	)
Payments on Long Term Notes			—				—				(45,000	)			—				—			(45,000	)
Other Financing Activities			42,906				6,654				(7,589	)			(2,000	)			—			39,971
Net Cash Provided By (Used in) Financing Activities		$	153,774			$	6,654			$	(52,589	)		$	(2,000	)		$	—		$	105,839

Supplemental Coal Data (unaudited):

 

		Millions of Tons For the Year Ended December 31,
		2009			2008			2007			2006			2005
Proved and probable reserves at beginning of period		4,543			4,526			4,272			4,546			4,509
Purchased reserves		5			—			177			3			56
Reserves sold in place		(3	)		(12	)		(33	)		(2	)		(2	)
Production		(59	)		(65	)		(65	)		(67	)		(69	)
Revisions and other changes		34			94			175			(208	)		52
Consolidated proved and probable reserves at end of period*		4,520			4,543			4,526			4,272			4,546
Proportionate share of proved and probable reserves of unconsolidated equity affiliates*		170			171			179			—			—

 

*	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.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

CONSOL Energy’s coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2009, 898 million tons were assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2009 include 3,960 million tons of steam coal reserves, of which approximately 8 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million British thermal unit (Btu), and an additional 14 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. The reserves also include 560 million tons of metallurgical coal in consolidated reserves, of which approximately 62 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu, and an additional 37 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. A significant portion of this metallurgical coal can also serve the steam coal market.

Other Supplemental Information—Supplemental Gas Data (unaudited)

The following information was prepared in accordance with the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).”

Capitalized Costs:

 

		As of December 31,
		2009				2008
Proved properties		$	152,010			$	121,605
Unproved properties			271,553				220,848
Wells and related equipment			1,171,146				1,019,880
Gathering assets			804,212				740,396
Total Property, Plant and Equipment			2,398,921				2,102,729
Accumulated Depreciation, Depletion and Amortization			(429,966	)			(319,959	)
Net Capitalized Costs		$	1,968,955			$	1,782,770

Costs incurred for property acquisition, exploration and development (*):

 

		For the Years Ended December 31,
		2009			2008			2007
Property acquisitions and other changes
Proved properties		$	30,405		$	17,090		$	33,205
Unproved properties			50,705			119,168			80,313
Development			181,944			378,119			257,935
Exploration			46,023			68,495			16,503
Total		$	309,077		$	582,872		$	387,956

 

(*)	Includes costs incurred whether capitalized or expensed.

 

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Results of Operations for Producing Activities:

 

		For the Twelve Months Ended December 31,
		2009						2008						2007
		Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates
Production Revenue		$	630,598		$	—		$	688,325		$	—		$	416,452		$	2,755
Royalty Interest Gas Revenue			40,951			—			79,302			—			46,586			294
Purchased Gas Revenue			7,040			—			8,464			—			7,628			201
Total Revenue			678,589			—			776,091			—			470,666			3,250
Lifting Costs			55,285			—			67,653			—			38,721			679
Gathering Costs			95,687			—			83,752			—			61,798			630
Royalty Interest Gas Costs			32,423			—			74,041			—			40,011			294
Other Costs			45,795			—			34,078			—			19,772			646
Purchased Gas Costs			6,442			—			8,175			—			7,162			165
DD&A			107,251			—			70,010			—			48,961			294
Total Costs			342,883			—			337,709			—			216,425			2,708
Pre-tax Operating Income			335,706			—			438,382			—			254,241			542
Income Taxes			125,890			—			171,407			—			98,595			210
Results of Operations for Producing Activities excluding Corporate and Interest Costs		$	209,816		$	—		$	266,975		$	—		$	155,646		$	332

The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:

 

		For the Years Ended December 31,
		2009			2008			2007
Production in million cubic feet			94,415			76,562			58,249
Average gas sales price before effects of financial settlements (per thousand cubic feet)		$	4.15		$	8.99		$	6.87
Average effects of financial settlements (per thousand cubic feet)		$	2.53		$	—		$	0.33
Average gas sales price including effects of financial settlements (per thousand cubic feet)		$	6.68		$	8.99		$	7.20
Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet)		$	0.48		$	0.58		$	0.39

During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Of these wells drilled in the year ended December 31, 2009 there was one dry well. There were no dry wells in the years ended December 31, 2008 and 2007.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

During the years ended December 31, 2009, 2008 and 2007, we drilled 18, 56 and 9 net exploratory wells, respectively. Of the wells drilled in the years ended December 31, 2009 and 2008, there were one and three dry wells, respectively. There were no dry wells in the year ended December 31, 2007.

At December 31, 2009, there were six development wells in the process of being drilled. Drilling activities are currently in progress to complete the drilling of these wells by the end of March 2010.

At December 31, 2009, there were ten exploratory wells in the process of being drilled. Drilling and evaluation activities will be in process throughout the 2010 period.

CNX Gas is committed to provide 44.1 Bcf of gas under existing contracts or agreements over the course of the next two years. CNX Gas expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.

Most of our development wells and proved acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied. The following table sets forth the number of CNX Gas producing wells, developed acreage and undeveloped acreage at December 31, 2009:

 

		Gross		Net(1)
Producing Wells (including gob wells)		5,240		3,926
Proved Developed Acreage		260,327		254,753
Proved Undeveloped Acreage		56,090		54,298
Unproved Acreage		3,957,174		3,399,490
Total Acreage		4,273,591		3,708,541

 

(1)

Net acres do not include acreage attributable to the working interests of our principal joint venture partners and the portions of certain proved developed acreage attributable to property we have leased to third-party producers. Additional adjustments (either increases or decreases) may be required as we further develop title to and confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Proved Oil and Gas Reserve Quantities:

The preparation of our gas reserve estimates are completed in accordance with CNX Gas’ prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer. Our 2009 gas reserve results were audited by Netherland, Sewell and Associates, Inc. The technical person primarily responsible for overseeing the audit of our reserves is a certified petroleum engineer. The gas reserve estimates are as follows:

 

		2009			2008						2007
		Consolidated Operations			Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates
Net Reserve Quantity (MMcfe)
Beginning reserves		1,422,046			1,339,909			3,584			1,263,293			2,200
Revisions(b)		177,004			(30,828	)		—			(25,036	)		221
Extensions and discoveries(c)		406,756			182,701			—			145,834			1,484
Production		(94,415	)		(76,562	)		—			(57,928	)		(321	)
Acquisition of remaining interest in equity affiliate		—			3,584			(3,584	)		—			—
Purchases of reserves in-place		—			3,242			—			13,746			—
Sale of reserves in-place		—			—			—			—			—
Ending reserves(a)		1,911,391			1,422,046			—			1,339,909			3,584

 

(a)

Proved developed and proved undeveloped gas reserves are defined by the Securities and Exchange Commission (SEC) Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX Gas cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas and coalbed methane gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.

(b)	Revisions are primarily due to efficiencies in operations which resulted in a reduction of operating costs, a comprehensive look into reservoir characterization and well performance.

(c)

Extensions and discoveries are due to the addition of our Marcellus Shale acreage and approvals from the Oil & Gas Board in Virginia to drill and complete wells on tighter spacing. Extensions and discoveries also include 120,933 MMcfe as a result of initially applying the amendments of ASC 932 in ASU 2010-03 related to capturing proved undeveloped locations more than one location away if reliable technology can be demonstrated.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

		2009						2008						2007
		All Products		Natural Gas mmcf		Oil mmcfe		All Products		Natural Gas mmcf		Oil mmcfe		All Products		Natural Gas mmcf		Oil mmcfe
Proved developed reserves (consolidated entities only)
Beginning of year		783,290		783,010		280		667,726		667,443		283		609,700		609,538		162
End of year		1,040,257		1,039,052		1,205		783,290		783,010		280		667,726		667,443		283
Proved undeveloped reserves (consolidated entities only)
Beginning of year		638,756		638,756		—		672,183		672,183		—		653,593		653,593		—
End of year		871,134		871,134		—		638,756		638,756		—		672,183		672,183		—

 

		For the Year Ended December 31, 2009
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves		638,756
Undeveloped reserves transferred to developed(a)		(118,145	)
Revisions		27,601
Extension and discoveries		322,922
Ending proved undeveloped reserves(b)		871,134

 

(a)	During 2009, various exploration and development drilling and evaluations were completed. Approximately, $45,326 of capital was spent in the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.

(b)

Included in proved undeveloped reserves at December 31, 2009 are approximately 120,000 MMcfe of reserves that have been reported for more than five years that relate specifically to CONSOL Energy’s Buchanan Mine. These undeveloped reserves will be developed in order to de-gas the mine ahead of longwall mining.

The following table represents the capitalized exploratory well cost activity as indicated:

 

		December 31, 2009
Costs pending the determination of proved reserves at December 31, 2009(a)
Less than one year		$	156
More than one year but less than five years			5,454
More than five years			2,627
Total		$	8,237

 

(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.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

		For the Years Ended December 31,
		2009			2008			2007
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves		$	52,332		$	1,887		$	402
Costs expensed due to determination of dry hole or abandonment of project		$	8,194		$	1,197		$	—

CNX Gas’ proved gas reserves are located in the United States.

Standardized Measure of Discounted Future Net Cash Flows:

The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year ended December 31, 2009. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CNX Gas. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CNX Gas’ investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a different price and cost assumptions.

The standardized measure is intended to provide a better means for comparing the value of CNX Gas’ proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.

 

		December 31,
		2009				2008				2007
Future Cash Flows:
Revenues		$	7,975,195			$	8,856,817			$	9,509,665
Production costs			(3,123,532	)			(3,525,902	)			(3,004,619	)
Development costs			(995,569	)			(793,592	)			(636,436	)
Income tax expense			(1,465,075	)			(1,713,713	)			(2,259,415	)
Future Net Cash Flows			2,391,019				2,823,610				3,609,195
Discounted to present value at a 10% annual rate			(1,496,668	)			(1,605,176	)			(2,219,655	)
Total standardized measure of discounted net cash flows(a)		$	894,351			$	1,218,434			$	1,389,540

 

(a)	The estimated effect on the PV-10 calculation of initially applying the amendments of ASC 932 in ASU 2010-03 was $39,059.

 

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

The following are the principal sources of change in the standardized measure of discounted future net cash flows during:

 

		December 31,
		2009				2008								2007
		Consolidated Operations				Consolidated Operations				Equity Affiliates				Consolidated Operations				Equity Affiliates
Balance at beginning of period		$	1,218,434			$	1,384,983			$	4,557			$	933,186			$	1,705
Net changes in sales prices and production costs			(333,130	)			(676,358	)			—				1,681,550				7,356
Sales net of production costs			(335,706	)			(438,382	)			—				(207,688	)			(1,122	)
Net change due to revisions in quantity estimates			189,583				(63,547	)			—				479,618				5,959
Net change due to acquisition			—				4,158				—				2,840				—
Acquisition of remaining interest in equity affiliate			—				4,557				(4,557	)			—				—
Development costs incurred during the period			181,944				378,119				—				257,935				—
Difference in previously estimated development costs compared to actual costs incurred during the period			(3,282	)			(136,742	)			—				(87,408	)			—
Changes in estimated future development costs			(380,639	)			(398,534	)			—				(254,635	)			(214	)
Net change in future income taxes			248,639				545,702				—				(754,209	)			(4,673	)
Accretion of discount and other			108,508				614,478				—				(666,206	)			(4,454	)
Total discounted cash flow at end of period		$	894,351			$	1,218,434			$	—			$	1,384,983			$	4,557

 

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Table of Contents

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

 

Supplemental Quarterly Information (unaudited):

(Dollars in thousands)

 

		Three Months Ended
		March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009
Sales		$	1,164,341		$	1,003,973		$	1,032,531		$	1,158,937
Freight Revenue		$	30,916		$	27,087		$	36,130		$	54,774
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests’ Costs and Purchased Gas Costs)		$	680,095		$	649,704		$	714,627		$	751,444
Freight Expense		$	30,916		$	27,087		$	36,130		$	54,774
Net Income		$	204,971		$	118,839		$	93,286		$	150,046
Net Income Attributable to CONSOL Energy Inc Shareholders		$	195,819		$	113,339		$	87,370		$	143,189
Total Earnings per Share
Basic		$	1.08		$	0.63		$	0.48		$	0.80
Diluted		$	1.08		$	0.62		$	0.48		$	0.77
Weighted Average Shares Outstanding
Basic			180,576,479			180,644,498			180,725,194			180,823,733
Diluted			182,150,090			183,073,413			183,191,667			183,651,382
		Three Months Ended
		March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008
Sales		$	906,368		$	1,135,572		$	1,076,960		$	1,150,435
Freight Revenue		$	44,744		$	63,927		$	60,458		$	47,839
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests’ Costs and Purchased Gas Costs)		$	656,223		$	764,137		$	762,767		$	742,213
Freight Expense		$	44,744		$	63,927		$	60,458		$	47,839
Net Income		$	84,231		$	112,790		$	102,416		$	186,224
Net Income Attributable to CONSOL Energy Inc Shareholders		$	75,082		$	101,012		$	90,054		$	176,322
Total Earnings per Share
Basic		$	0.41		$	0.55		$	0.49		$	0.98
Diluted		$	0.41		$	0.54		$	0.49		$	0.97
Weighted Average Shares Outstanding
Basic			182,572,985			182,977,726			183,202,086			180,799,712
Diluted			185,192,551			185,637,248			185,591,759			182,327,963

 

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Table of Contents

DEPI, Dominion Reserves and DTI Exploration

and Production

Combined Financial Statements for the years ended December 31, 2009, 2008 & 2007

and

Independent Auditors’ Report

 

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CONTENTS

 

		Page Number
Independent Auditors’ Report		F-79
Combined Statements of Income for the years ended December 31, 2009, 2008 and 2007		F-80
Combined Balance Sheets at December 31, 2009 and 2008		F-81
Combined Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007		F-83
Combined Statements of Shareholders’ Equity and Comprehensive Income at December 31, 2009, 2008 and 2007 and for the years then ended		F-84
Notes to Combined Financial Statements		F-85

 

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Table of Contents

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Shareholders of

Dominion Resources, Inc.

Richmond, VA

We have audited the accompanying combined balance sheet of Dominion Exploration and Production Inc. and subsidiaries, Dominion Reserves Inc. and subsidiaries, and the producing business of Dominion Transmission Inc. (collectively “the Combined Companies”), all of which are under common ownership and common management, as of December 31, 2009 and December 31, 2008, and the related combined statements of income and shareholders’ equity and comprehensive income and of cash flows for each of the three years in the period ended December 31, 2009. These combined financial statements are the responsibility of the Combined Companies’ management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing 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. The Combined Companies were not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Combined Companies’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of the Combined Companies as of December 31, 2009 and December 31, 2008, and the combined results of their operations and their combined cash flows for each of the three years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the combined financial statements, the Combined Companies changed its methods of accounting to adopt new accounting standards for oil and gas accounting and reporting in 2009 and fair value measurements in 2008.

/s/ Deloitte & Touche LLP

Richmond, Virginia

March 14, 2010

 

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Table of Contents

Dominion Exploration & Production

Combined Statements of Income

 

Year Ended December 31,		2009				2008				2007
(thousands)
Operating Revenue
Affiliated sales, net		$	298,599			$	361,907			$	415,635
Other(1)			44,358				(314	)			211,119
Total operating revenue		$	342,957			$	361,593			$	626,754
Operating Expenses
Purchased commodities:
Affiliated suppliers			—				—				39,664
Other			—				—				45,060
Production (lifting)			66,115				69,815				248,441
General and administrative:
Affiliated services			19,648				22,975				54,271
Other			16,740				29,920				131,518
Ceiling test impairment			282,775				—				—
Depreciation, depletion and amortization			72,497				84,350				295,656
Total operating expenses			457,775				207,060				814,610
Gain on sale of non-Appalachian E&P business			—				—				(3,175,618	)
Income (loss) from operations			(114,818	)			154,533				2,987,762
Other Expense
Net interest expense (income):
Affiliated			35,125				36,687				42,368
Other			(941	)			(1,800	)			(14,018	)
Total other expense			34,184				34,887				28,350
Income (loss) before income taxes			(149,002	)			119,646				2,959,412
Income taxes			(61,394	)			41,856				1,111,125
Net Income (Loss)		$	(87,608	)		$	77,790			$	1,848,287

 

(1)	The Other losses in 2008 are due to losses on derivative positions with non-affiliates of $28 million.

 

The accompanying notes are an integral part of the Combined Financial Statements.

 

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Table of Contents

Dominion Exploration & Production

Combined Balance Sheets

 

At December 31,		2009				2008
(thousands)
ASSETS
Current Assets
Cash and cash equivalents		$	36			$	3
Accounts receivables:
Customer			8,665				11,718
Affiliate			27,534				37,775
Other receivables (less allowance for doubtful accounts of $4,909 and $4,410)			3,392				42,036
Affiliated advances			—				362,100
Derivative assets:
Affiliate			45,655				56,398
Non-affiliate			—				19,612
Prepayments			7,309				18,063
Other			3,405				16,461
Total current assets			95,996				564,166
Investments			925				828
Property, Plant and Equipment (full cost method)
Proved properties			1,668,586				1,515,633
Unproved properties			8,416				10,838
Other			6,344				19,282
Total property, plant and equipment			1,683,346				1,545,753
Accumulated depreciation, depletion and amortization			(678,476	)			(329,628	)
Net property, plant and equipment			1,004,870				1,216,125
Deferred Charges and Other Assets
Affiliated employer benefit assets			20,240				20,790
Affiliated derivative assets			3,131				20,589
Noncurrent income taxes receivable and other assets			32,069				21,530
Total deferred charges and other assets			55,440				62,909
Total assets		$	1,157,231			$	1,844,028

 

The accompanying notes are an integral part of the Combined Financial Statements.

 

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At December 31,		2009				2008
(thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable		$	36,282			$	43,591
Payables to affiliates			2,090				233,879
Affiliated current borrowings			115,579				182,374
Accrued interest, payroll and taxes			40,723				38,815
Deferred income taxes			9,212				29,752
Other			19,981				55,466
Total current liabilities			223,867				583,877
Long-Term Debt
Affiliated notes payable			528,530				530,460
Total long-term debt			528,530				530,460
Deferred Credits and Other Liabilities
Deferred income taxes			266,079				333,652
Asset retirement obligations			122,587				113,805
Affiliated employer benefit liabilities			26,990				26,347
Other			23,949				21,421
Total deferred credits and other liabilities			439,605				495,225
Total liabilities			1,192,002				1,609,562
Commitments and Contingencies (see Note 14)
Common Shareholders’ Equity
Common equity			115,608				233,665
Parent investment in DTI producing activities			(27,457	)			(22,903	)
Retained deficit			(151,827	)			(29,898	)
Accumulated other comprehensive income			28,905				53,602
Total common shareholders’ equity			(34,771	)			234,466
Total liabilities and shareholders’ equity		$	1,157,231			$	1,844,028

 

The accompanying notes are an integral part of the Combined Financial Statements.

 

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Table of Contents

Dominion E&P

Combined Statements of Cash Flows

 

Year Ended December 31,		2009				2008				2007
(thousands)
Operating Activities
Net income (loss)		$	(87,608	)		$	77,790			$	1,848,287
Adjustments to reconcile net income (loss) to net cash from operating activities:
Impairment of gas and oil properties			282,775				—				—
Gain on sale of non-Appalachian E&P business			—				—				(3,175,618	)
Charges related to termination of VPP agreements			—				—				77,266
Net change in realized and unrealized derivative (gains) losses			4,396				47,230				(166,176	)
Depreciation, depletion and amortization			72,497				84,350				295,656
Deferred income taxes			(70,999	)			(7,837	)			(716,615	)
Other adjustments			3,314				5,936				(798	)
Changes in:
Accounts receivable			41,697				66,632				206,014
Affiliated accounts receivable and payable			(25,586	)			(22,005	)			480,618
Inventories			(49	)			(284	)			(5,231	)
Prepayments			10,753				(13,546	)			38,922
Accounts payable			744				(110,800	)			(126,266	)
Accrued interest, payroll and taxes			1,908				(197,110	)			180,845
Margin deposit assets and liabilities			—				(81,776	)			75,480
Other operating assets and liabilities			(21,375	)			(48,644	)			158,473
Net cash provided by (used in) operating activities			212,467				(200,064	)			(829,143	)
Investing Activities
Oil and natural gas property and other expenditures			(175,119	)			(238,873	)			(1,065,694	)
Proceeds from assignment of natural gas drilling rights			—				342,917				—
Advances to affiliates, net of repayment			—				174,532				(2,854,778	)
Proceeds from sale of non-Appalachian E&P business			—				—				7,046,432
Proceeds from sale of gas and oil properties			22,239				—				—
Other			—				77				(5,546	)
Net cash provided by (used in) investing activities			(152,880	)			278,653				3,120,414
Financing Activities
Issuance (repayment) of affiliated current borrowings, net			4,766				16,032				(1,874,414	)
Repayment of affiliated notes payable			(1,930	)			(187	)			(223,073	)
Common dividend payments			(43,468	)			(66,636	)			(162,061	)
Capital distribution			(18,875	)			(29,105	)			(36,692	)
Other			(47	)			296				(1,096	)
Net cash used in financing activities			(59,554	)			(79,600	)			(2,297,336	)
Increase (decrease) in cash and cash equivalents			33				(1,011	)			(6,065	)
Cash and cash equivalents at beginning of year			3				1,014				7,079
Cash and cash equivalents at end of year		$	36			$	3			$	1,014
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts		$	34,349			$	37,471			$	27,807
Income taxes			7,316				271,026				1,533,611
Significant noncash investing and financing activities:
Accrued capital expenditures			3,977				14,369				19,779
Conversion of short-term and long-term borrowings, advances and payables to equity			94,578				(44,690	)			2,846,322

The accompanying notes are an integral part of the Combined Financial Statements.

 

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Dominion E&P

Combined Statements of Shareholders’ Equity and Comprehensive Income

 

		Common Equity				Retained Earnings (Deficit)				Accumulated Other Comprehensive Income (loss)(1)				Parent Investment in DTI-E&P				Total
(thousands, except shares)
Balance at December 31, 2006		$	1,043,681			$	316,389			$	(307,544	)		$	(10,387	)		$	1,042,139
Comprehensive income:
Net Income							1,828,038								20,249				1,848,287
Net deferred gains (losses) on derivatives-hedging activities, net of $60,795 tax											(93,926	)							(93,926	)
Net derivative (gains) losses reclassified to net income-hedging activities, net of $(240,367) tax											409,274								409,274
Total comprehensive income							1,828,038				315,348				20,249				2,163,635
Stock repurchase and retirement			(190,230	)															(190,230	)
Capital distribution			(532,950	)			(2,123,561	)							(36,692	)			(2,693,203	)
Dividends			(145,848	)			(16,213	)											(162,061	)
Tax effect of stock awards			1,693																1,693
Cumulative effect of change in accounting principle							(204	)											(204	)
Balance at December 31, 2007			176,346				4,449				7,804				(26,830	)			161,769
Comprehensive income:
Net Income							44,758								33,032				77,790
Net deferred gains (losses) on derivatives-hedging activities, net of $(22,345) tax											32,648								32,648
Net derivative (gains) losses reclassified to net income-hedging activities, net of $(9,156) tax											13,150								13,150
Total comprehensive income							44,758				45,798				33,032				123,588
Capital contribution (distribution)			123,795				(79,105	)							(29,105	)			15,585
Dividends			(66,636	)															(66,636	)
Tax effect of stock awards			160																160
Balance at December 31, 2008			233,665				(29,898	)			53,602				(22,903	)			234,466
Comprehensive income:
Net Income (loss)							(101,929	)							14,321				(87,608	)
Net deferred gains (losses) on derivatives-hedging activities, net of $(37,050) tax											55,401								55,401
Net derivative (gains) losses reclassified to net income-hedging activities, net of $54,164 tax											(80,098	)							(80,098	)
Total comprehensive income (loss)							(101,929	)			(24,697	)			14,321				(112,305	)
Capital distribution			(74,578	)			(20,000	)							(18,875	)			(113,453	)
Dividends			(43,468	)															(43,468	)
Tax effect of stock awards			(11	)															(11	)
Balance at December 31, 2009		$	115,608			$	(151,827	)		$	28,905			$	(27,457	)		$	(34,771	)

 

(1)	All AOCI for 2007, 2008 and 2009 relates to derivatives and hedging activities.

The accompanying notes are an integral part of the Combined Financial Statements.

 

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Note 1. Business Description and Basis of Presentation

Dominion Exploration & Production Inc. (DEPI), Dominion Reserves, Inc, and Dominion Transmission Inc. (DTI) are wholly-owned subsidiaries of Dominion Resources, Inc. (Dominion), one of the nation’s largest producers and transporters of energy. Our combined financial statements include the entirety of these wholly-owned subsidiaries, other than DTI, for which these financial statements only include the exploration and production (E&P) business of DTI (DTI-E&P). DEPI’s capital structure includes 70,000 shares of $10,000 par value common stock authorized for issuance. As of December 31, 2009 and 2008, there were 24,877 shares of DEPI common stock outstanding. DEPI’s consolidated financial statements include the wholly-owned subsidiaries Dominion Coal Bed Methane Inc. (DCBM) and DEPI Texas Holdings, LLC. Dominion Reserves, Inc’s capital structure includes 100 shares of common stock – no par value authorized for issuance. As of December 31, 2009 and 2008, there were 10 shares of Dominion Reserves, Inc. common stock outstanding. Dominion Reserves, Inc’s consolidated financial statements include the wholly-owned subsidiaries Dominion Appalachian Development Properties LLC, Dominion Appalachian Development LLC, Carthage Energy Services, LLC, Dominion Midwest Energy LLC, and Dominion Gas Processing MI, Inc. Together, the wholly-owned subsidiaries and DTI-E&P are referred to as the “Companies”, “Dominion E&P”, “we” or “us”.

The Dominion E&P business generates income from the sale of natural gas and oil it produces from its reserves in the Appalachian Basin of the U.S. and its non-Appalachian reserves prior to their sale during 2007 (See Note 4), including production from fixed-term overriding royalty interests formerly associated with its volumetric production payment (VPP) agreements, which terminated in June 2007. At December 31, 2009, the Companies own approximately 1.3 trillion cubic feet equivalent of proved natural gas and oil reserves and produce approximately 137 million cubic feet equivalent (mcf) of natural gas and oil per day from our leasehold acreage and facility investments in Appalachia.

During March 2010, Dominion began exploring a potential transaction to sell the majority of its remaining Dominion E&P operations. In preparation for the potential transaction, the accompanying Combined Financial Statements and Notes were prepared from the historical accounting records of the Companies for the purpose of complying with Rule 3-05 of Regulation S-X of the Securities and Exchange Commission (SEC). The accompanying Combined Financial Statements and Notes are not necessarily indicative of the financial condition or results of operations of the gas and oil properties going forward because of changes in the business and the exclusion of certain corporate-related expenses such as corporate governance, investor relations, and legal fees related to debt issuances.

Note 2. Significant Accounting Policies

Principles of Consolidation

Our combined financial statements include, after eliminating intercompany transactions and balances, the accounts of our respective wholly-owned subsidiaries and of the exploration and production business of DTI.

Use of Estimates

We make certain estimates and assumptions in preparing our combined financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

DTI-E&P Allocations

Historically, the DTI-E&P business was not operated or accounted for as a legal entity but was an integrated part of DTI. For accounts that are not specific to the DTI-E&P business, certain allocation methodologies were

 

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used to allocate these DTI-E&P accounts to our Combined Financial Statements. Significant DTI-E&P allocations include:

 

•

Trade accounts payable, which is allocated based on DTI-E&P’s operations and maintenance (O&M) expenses as a percentage of DTI’s total O&M expenses.

 

•

Notes payable to affiliates, which is allocated based on DTI-E&P’s net property, plant and equipment as a percentage of DTI’s total net property, plant and equipment.

 

•

Accrued payroll, which is allocated based on DTI-E&P’s employee salaries and benefits as a percentage of DTI’s total employee salaries and benefits.

 

•

Long-term debt, which is allocated based on DTI-E&P’s net property, plant and equipment as a percentage of DTI’s total net property, plant and equipment.

 

•

Affiliated employer benefit assets and liabilities, which are allocated based on DTI-E&P’s employee salaries and benefits as a percentage of DTI’s total employee salaries and benefits.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2009 and 2008, the Companies’ accounts payable included $6 million and $9 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Combined Balance Sheets and Combined Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Property, Plant and Equipment

We follow the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, discounted at 10%, using trailing twelve month average natural gas and oil prices adjusted for cash flow hedges in place. Prior to adoption of the SEC’s Final Rule, Modernization of Oil and Gas Reporting, effective December 31, 2009, period-end gas and oil prices were used when performing the full cost ceiling test calculation; however, subsequent commodity prices could be utilized to reduce or eliminate any impairment in accordance with SEC guidelines. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. At December 31, 2009, approximately 3% of our anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Using trailing twelve month average prices, adjusted for cash flow hedges in place, there was no ceiling test impairment at December 31, 2009. Excluding the effects of hedge-adjusted prices in calculating the ceiling test limitation would have resulted in an approximately $66 million ($39 million after-tax) ceiling test impairment at December 31, 2009.

In 2009, we recorded a ceiling test impairment charge of $283 million ($169 million after-tax) in our Combined Statement of Income. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $459 million ($275 million after-tax). Future cash flows associated with settling asset retirement obligations (AROs) that have been accrued in our Combined Balance Sheets are excluded from our calculations under the full cost ceiling test. Decreases in commodity prices, as well as changes

 

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in production levels, reserve estimates, future development costs, lifting costs and other factors could result in future ceiling test impairments.

Depletion of gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depletable base of costs subject to depletion also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties including associated exploration-related costs are initially excluded from the depletable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depletable base, determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depletable base. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost pool. As discussed in Note 4, in 2007, we recognized gains from the sales of our U.S. non-Appalachian E&P businesses.

All other property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. Intangible assets with finite lives are amortized over their estimated useful lives or as consumed. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as incurred. In 2009, 2008 and 2007, we capitalized interest costs of $0.5 million, $0.5 million, and $15 million, respectively. Depreciation of property, plant and equipment is computed on the straight-line method, based on projected service lives. In 2009, 2008 and 2007, depreciation and depletion expense was $72 million, $84 million and $284 million, respectively.

We perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.

Revenue Recognition

Gas and oil production revenue is recognized based on actual volumes of gas and oil sold to purchasers, is reported net of royalties and includes amounts yet to be billed to purchasers. Sales require delivery of the product to the purchaser, passage of title, and probability of collection of purchaser amounts owed. Revenue from sales of gas production includes the sale of Company produced gas and the recognition of revenue from the VPP transactions described in Note 4. We use the sales method of accounting for gas imbalances related to gas production. An imbalance is created when Company volumes of gas sold pertaining to a property do not equate to the volumes to which we are entitled based on our interest in the property. A liability is recognized when our excess sales over entitled volumes exceeds our net remaining property reserves.

Prior to the sale of our non-Appalachian E&P business, we entered into buy/sell and related agreements primarily as a means to reposition our offshore Gulf of Mexico crude oil production to more liquid onshore marketing locations and to facilitate gas transportation. Activity related to buy/sell and related agreements was reported on a gross basis prior to the adoption of new accounting guidance for purchases and sales of inventory with the same counterparty in April 2006. Following the adoption of this guidance, a significant portion of our activity related to buy/sell and related agreements was presented on a net basis in our Combined Statements of Income if the agreements were entered into in contemplation of one another; however, there was no impact on our results of operations or cash flows. Following the sale of our non-Appalachian E&P business in 2007, this activity did not have a material effect in our Combined Statements of Income.

Derivatives

We use derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of our natural gas and oil production.

 

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All derivatives, except those for which an exception applies, are required to be reported on our Combined Balance Sheets at fair value. Derivative contracts representing unrealized gain positions are reported as derivative assets. Derivative contracts representing unrealized losses are reported as derivative liabilities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date.

We do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At December 31, 2009 and 2008, we did not have any margin assets or liabilities related to cash collateral.

Derivative Instruments Not Designated as Cash Flow Hedging Instruments

We hold certain non-trading derivative instruments that are not designated as hedges for accounting purposes. However, to the extent we do not hold offsetting positions for such derivatives, we believe these instruments represent economic hedges that mitigate our exposure to fluctuations in commodity prices.

Statement of Income Presentation—Derivatives Not Held for Trading Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in operating revenue in our Statements of Income.

Derivative Instruments Designated as Cash Flow Hedging Instruments

We designate a substantial portion of our derivative instruments as cash flow hedges for accounting purposes. The cash flow hedging strategies are primarily used to hedge the variable price risk associated with the sale of natural gas and oil. For all derivatives designated as cash flow hedges, the relationship between the hedging instrument and the hedged item is formally documented, as well as the risk management objective and strategy for using the hedging instrument at the inception of the hedge. For transactions in which we are hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (loss) (AOCI), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows, both at the inception of the hedging relationship and on an ongoing basis. Any change in fair value of the derivative that is not effective at offsetting changes in the cash flows of the hedged item is recognized currently in earnings. Also, we may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to the time value of options, which are recognized currently in earnings. We discontinue hedge accounting prospectively for derivatives that have ceased to be highly effective hedges or for which the forecasted transaction is determined to be no longer probable. We reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it becomes probable that the forecasted transaction will not occur.

Statement of Income Presentation—Gains and losses on derivatives designated as hedges, when recognized, and gains and losses on hedging instruments determined to be ineffective are included in operating revenue in our Statements of Income.

Valuation Methods

See Note 7 for further information about fair value measurements and associated valuation methods for derivatives.

Fair Value of Financial Instruments

In accordance with GAAP, we report certain contracts and instruments at fair value. The carrying values of the Companies’ receivables and payables are estimated to be substantially the same as their fair values at

 

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December 31, 2009 and 2008. See Note 7 for fair value disclosures related to the Companies’ debt. See Notes 7 and 8 for details about the fair value of the Companies’ derivative financial instruments.

Income Taxes

Dominion E&P is included in the consolidated federal income tax return of Dominion and its subsidiaries. In addition, where applicable, Dominion E&P is included in combined state income tax returns of Dominion and its subsidiaries; otherwise, Dominion E&P files separate state income tax returns. In connection with being included in Dominion’s consolidated or combined income tax returns, Dominion E&P participates in an intercompany tax sharing agreement with Dominion and its subsidiaries. Under the tax sharing agreement, Dominion E&P’s current income taxes are based on its taxable income or loss, determined on a separate company basis. In addition, Dominion E&P recognizes an intercompany receivable from Dominion and is paid for net operating losses, if the tax benefit is realized by the consolidated group.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion E&P establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized.

Dominion E&P recognizes positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. When uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities.

Dominion E&P’s policy is to recognize changes in interest payable on net underpayments and overpayments of income taxes in interest expense and penalties in general and administrative expense. In our Combined Statements of Income, Dominion E&P recognized no material penalties and a reduction of interest expense of $0.2 million and $1 million in 2009 and 2008, respectively, and interest expense of $2 million in 2007. Dominion E&P had accrued interest receivable of $2 million and no penalties payable at December 31, 2009, and interest receivable of $0.4 million and no penalties payable at December 31, 2008.

Asset Retirement Obligations

We recognize AROs at fair value as incurred, or when sufficient information becomes available to determine a reasonable estimate of the fair value of the retirement activities to be performed. The associated asset retirement costs are capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, we estimate fair value using discounted cash flow analyses. We report the accretion of the AROs due to the passage of time in production (lifting) expense.

Note 3. Newly Adopted Accounting Standards

2009

SEC Final Rule, Modernization of Oil and Gas Reporting

Effective December 31, 2009, we adopted the SEC Final Rule, Modernization of Oil and Gas Reporting, which revised the existing Regulation S-K and Regulation S-X accounting and reporting requirements. Under the new requirements, the ceiling test is calculated using an average price based on the prior twelve month period

 

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rather than period-end prices. As a result, going forward we will be less likely to experience a ceiling test impairment based solely on a sudden decrease in gas and oil prices.

2008

Fair Value Measurements

We adopted new Financial Accounting Standards Board (FASB) guidance effective January 1, 2008, which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. The guidance applies broadly to financial and non-financial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances. Generally, the provisions of this guidance were applied prospectively. In February 2008, the FASB amended the fair value measurements guidance to exclude leasing transactions. However, the exclusion does not apply to fair value measurements of assets and liabilities recorded as a result of a lease transaction but measured pursuant to other pronouncements within the scope of the fair value measurements guidance. See Note 7 for further information on fair value measurements.

2007

Accounting for Uncertainty in Income Taxes

Effective January 1, 2007, we adopted new FASB guidance for accounting for uncertainty in income taxes. As a result of the implementation of this guidance, we recorded a $0.2 million charge to beginning retained earnings, representing the cumulative effect of the change in accounting principle. At January 1, 2007, we had unrecognized tax benefits of $33 million. For the majority of these unrecognized tax benefits, the ultimate deductibility was highly certain, but there was uncertainty about the timing of such deductibility.

Note 4. Acquisitions and Dispositions

Acquisition of E&P Properties

In November 2007, we completed the acquisition of DCBM for approximately $6 million in cash. At the time of acquisition, DCBM included four coal bed methane leases covering approximately 43,667 acres of Pittsburgh Coal in Wetzel County, West Virginia including six horizontal coal bed methane wells.

Sale of E&P Properties

In 2007, we completed the sale to unrelated third parties of our non-Appalachian natural gas and oil E&P operations and assets for approximately $7 billion. We distributed most of the after-tax proceeds from these dispositions to our parent company, Dominion. The results of operations for our non-Appalachian E&P business were not reported as discontinued operations in the Combined Statements of Income since we did not sell our entire U.S. cost pool, which includes the retained Appalachian assets.

The sales of our non-Appalachian E&P operations resulted in the discontinuance of hedge accounting for certain cash flow hedges since it became probable that the forecasted sales of gas and oil would not occur. In connection with the discontinuance of hedge accounting for these contracts, we recognized charges, recorded in operating revenue in the Combined Statement of Income, predominantly reflecting the reclassification of losses from AOCI to earnings of $410 million ($261 million after-tax) in 2007. We terminated these gas and oil derivatives subsequent to the disposal of the non-Appalachian E&P business.

During 2007, we also recorded a charge in operating revenue in the Combined Statement of Income of approximately $77 million ($49 million after-tax) for the recognition of certain VPP agreements to which we were a party, that previously qualified for the normal purchase and sales exemption. We paid approximately $250 million to terminate the agreements on behalf of the Companies as well as other Dominion affiliates, and another

 

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Dominion affiliate assumed the VPP royalty interests formerly associated with these agreements. We received approximately $230 million for this conveyance of mineral interests under the terms of a new VPP agreement with an affiliated company.

Additionally, we recognized expenses for employee severance, retention and other costs of $52 million ($33 million after-tax) in 2007, related to the sale of our non-Appalachian E&P business, which are reflected in general and administrative expenses in our Combined Statement of Income.

We recognized a gain of approximately $3.2 billion ($2.0 billion after-tax) from the disposition of our non-Appalachian E&P operations. This gain excludes severance and retention costs and costs associated with the discontinuance of hedge accounting and recognition of forward gas contracts.

Sale of Oil and Gas Leases

During 2009, we sold certain oil and gas leases to unrelated third parties. In March 2009, we sold leases covering 2,686 acres in Bradford County, Pennsylvania for $7 million in cash, and in October 2009 we sold leases covering 12,696 acres in Bradford, Susquehanna, and Tioga Counties in Pennsylvania and Chemung County, New York for approximately $15 million in cash.

Note 5. Operating Revenue

Our operating revenue consists of the following:

 

Year Ended December 31,		2009			2008			2007
(thousands)
Gas sales		$	325,013		$	335,013		$	576,622
NGL sales			9,852			17,966			43,074
Oil and condensate sales(1)			5,765			8,215			(4,668	)
Other			2,327			399			11,726
Total operating revenue		$	342,957		$	361,593		$	626,754

 

(1)	The loss reflected in oil and condensate sales in 2007 was primarily due to the reclassification of losses from AOCI to earnings from the de-designation of cash flow hedges due to the sale of our Non-Appalachian E&P operations. See Note 4.

Note 6. Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. The tax returns of Dominion E&P are subject to routine audits by tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

The American Recovery and Reinvestment Act of 2009 includes provisions to stimulate economic growth, including incentives for increased capital investment by business and incentives to promote renewable energy. Under the act, Dominion E&P has claimed bonus tax depreciation in 2009 for qualifying expenditures which reduced their income taxes payable and increased deferred tax liabilities for the period.

 

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Details of Dominion E&P’s income tax expense were as follows:

 

Year Ended December 31,		2009				2008				2007
(thousands)
Current:
Federal		$	6,295			$	13,651			$	1,758,140
State			3,310				36,042				69,600
Total current			9,605				49,693				1,827,740
Deferred:
Federal			(59,823	)			30,032				(775,041	)
State			(11,176	)			(37,869	)			58,426
Total deferred			(70,999	)			(7,837	)			(716,615	)
Total income tax expense (benefit)		$	(61,394	)		$	41,856			$	1,111,125

Income taxes calculated on Dominion E&P’s income before taxes at the statutory U.S. federal income tax rate reconciles to its income tax provision as follows:

 

Year Ended December 31,		2009				2008				2007
(thousands)
Income (loss) before income taxes		$	(149,002	)		$	119,646			$	2,959,412
Total income tax expense (benefit) at U.S. statutory rate (35%)		$	(52,150	)		$	41,876			$	1,035,794
Increases (reductions) resulting from:
State taxes, net of federal benefit			(5,113	)			10,012				84,599
Legislative changes			—				(11,199	)			399
Domestic production activities			(3,951	)			—				(7,926	)
Other, net			(180	)			1,167				(1,741	)
Income tax expense (benefit)		$	(61,394	)		$	41,856			$	1,111,125

In 2007, Dominion E&P’s effective tax rate reflected the effects of the sale of its U.S. non-Appalachian E&P operations, including the reversal of $14 million of valuation allowances on deferred tax assets that related to state loss carryforwards utilized to partially offset taxes otherwise payable on the gain from the sale.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Dominion E&P’s deferred income taxes consist of the following:

 

At December 31,		2009				2008
(thousands)
Deferred income taxes:
Total deferred income tax assets		$	(21,684	)		$	(32,799	)
Total deferred income tax liabilities			296,975				396,203
Total net deferred income tax liabilities		$	275,291			$	363,404
Gas and oil exploration and production differences		$	262,344			$	327,496
Deferred state income taxes			12,403				23,773
Employee benefits			(8,638	)			(11,983	)
Price risk management activities			15,549				32,132
Other			(6,367	)			(8,014	)
Total net deferred income tax liabilities		$	275,291			$	363,404

 

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At December 31, 2009, Dominion E&P had no loss or credit carryforwards.

Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. The amount of tax return positions that are not recognized in the financial statements is disclosed as unrecognized tax benefits. These unrecognized tax benefits may impact the financial statements by increasing taxes payable, reducing tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of amounts is limited to the timing of such deductibility, any tax liabilities recognized for prior periods would be subject to offset with the availability of refundable amounts from later periods when such deductions could otherwise be taken. Pending resolution of these timing uncertainties, interest is being accrued until the period in which the amounts would become deductible.

A reconciliation of changes in Dominion E&P’s unrecognized tax benefits follows:

 

		2009				2008				2007
(thousands)
Balance at January 1		$	24,746			$	23,696			$	32,899
Increases—prior period positions			—				1,270				1,535
Decreases—prior period positions			(3,248	)			(288	)			(1,205	)
Current period positions			19				68				22,741
Prior period positions becoming otherwise deductible in current period			—				—				(23,111	)
Settlements with tax authorities			(1,171	)			—				(9,163	)
Balance at December 31		$	20,346			$	24,746			$	23,696

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. For Dominion E&P, these unrecognized tax benefits totaled $15 million, $20 million and $19 million at December 31, 2009, 2008 and 2007, respectively, and $0.2 million at January 1, 2007. Changes in these unrecognized tax benefits decreased income tax expense by $3 million in 2009 and increased income tax expense by $0.7 million and $18 million in 2008 and 2007, respectively.

For Dominion, the U.S. federal statute of limitations has expired for years prior to 2002. The status of Dominion’s consolidated U.S. federal returns as of December 31, 2009 and related 2009 activities follows:

 

•

The U.S. Congressional Joint Committee on Taxation completed its review of Dominion’s settlement with the Appellate Division of the Internal Revenue Service (IRS) for tax years 1999 through 2001.

 

•

Dominion and the Appellate Division of the IRS were engaged in settlement negotiations regarding certain proposed adjustments for tax years 2002 and 2003.

 

•

The IRS completed its audit of tax years 2004 and 2005, and Dominion and the IRS reached agreement on adjustments related to Dominion E&P.

With regard to tax years 2006 through 2009, Dominion E&P cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2010.

 

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For each of the major states in which Dominion E&P has operated or continues to operate, the earliest tax year remaining open for examination is as follows:

 

		Earliest Open Tax Year
Louisiana *		2002
Michigan		2005
Oklahoma		2006
Pennsylvania		2006
Utah *		2002
West Virginia		2006

 

*	State statute of limitations suspended with extension of federal statute of limitations.

Dominion E&P is also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion E&P utilizes state net operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.

Note 7. Fair Value Measurements

As described in Note 3, we adopted new FASB guidance for fair value measurements effective January 1, 2008. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair value is based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). We apply fair value measurements to commodity derivative instruments in accordance with the requirements described above. We apply credit adjustments to our derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.

We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, we consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases we must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect our market assumptions. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

 

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Also, we utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value, into three broad levels:

 

•

Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 would consist of financial instruments such as the majority of exchange-traded derivatives.

 

•

Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps.

 

•

Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 consist of long-dated commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are based on unobservable inputs due to market illiquidity and are therefore categorized as Level 3.

As of December 31, 2009, we did not hold any derivatives or other instruments categorized as Level 3. As of December 31, 2008, our net balance of commodity derivatives categorized as Level 3 was a net asset of $1 million. A hypothetical 10% increase in commodity prices would have decreased the net asset by $0.6 million. A hypothetical 10% decrease in commodity prices would have increased the net asset by $0.6 million.

Nonrecurring Fair Value Measurements

FASB fair value measurement guidance became effective for non-financial assets and liabilities on January 1, 2009. As such, the guidance applies to new AROs incurred after January 1, 2009 and upward revisions of existing AROs after January 1, 2009. During 2009, we incurred AROs related to newly drilled wells, which were initially measured at a fair value totaling approximately $2 million. Fair value was estimated using a discounted cash flow model based upon expected costs to plug and abandon the wells at the end of their useful lives. Cost information was based on historical costs to abandon similar wells. This is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future costs to be incurred.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3.

 

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The following table presents our assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

 

		Level 1		Level 2			Level 3			Total
(thousands)
At December 31, 2009
Assets:
Derivatives		—		$	48,786			—		$	48,786
Liabilities:
Derivatives		—		$	208			—		$	208
At December 31, 2008
Assets:
Derivatives		—		$	95,376		$	1,223		$	96,599
Liabilities:
Derivatives		—		$	1,812			—		$	1,812

The following table presents the net change in our assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

 

		2009(1)				2008(1)
(thousands)
Balance at January 1,
Total realized and unrealized gains (losses):		$	1,223			$	—
Included in other comprehensive income (loss)			(310	)			3,420
Transfers out of Level 3			(913	)			(2,197	)
Balance at December 31,		$	—			$	1,223

 

(1)	Represents derivative assets and liabilities presented on a net basis.

For the years ended December 31, 2009 and 2008, there were no gains or losses recorded in earnings related to derivatives categorized as Level 3.

Fair Value of Financial Instruments

Substantially all of our financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. At December 31, 2009 and 2008, the carrying amount of our customer and other receivables, and accounts payable are representative of fair value because of the short-term nature of these instruments. The financial instruments reported at historical cost along with their fair values are as follows:

 

At December 31,		2009						2008
		Carrying Amount			Estimated Fair Value(1)			Carrying Amount			Estimated Fair Value(1)
(thousands)
Notes payable to affiliates		$	528,530		$	560,661		$	530,460		$	484,743

 

(1)

Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

 

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Note 8. Derivatives and Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas and oil marketed as part of our business operations. We use derivative instruments to manage our exposure to these risks and designate certain derivative instruments as cash flow hedges for accounting purposes. See Note 7 for further information about fair value measurements and associated valuation methods for derivatives.

The following table presents the volume of our open derivative positions as of December 31, 2009. These volumes represent the combined absolute value of our long and short positions, except in the case of offsetting deals, for which we present the absolute value of the net volume of our long and short positions.

 

		Current		Noncurrent
Natural Gas (bcf)		26.4		6.3

Selected information about our hedge accounting activities follows:

 

Year Ended December 31,		2009			2008			2007
(thousands)
Portion of gains on hedging instruments determined to be ineffective and included in net income:
Cash Flow Hedges(1)(2)		$	50		$	393		$	48,257
Gains (losses) attributable to changes in the time value of options and excluded from the assessment of effectiveness
Cash Flow Hedges			—			—			(407	)
Total		$	50		$	393		$	47,850

 

(1)	For 2007, primarily represents changes in the fair value differential between the delivery location and commodity specifications of derivatives and the delivery location and commodity specifications of forecasted gas and oil sales.

(2)	For 2009, amounts were recorded in operating revenue.

See Note 4 for a discussion of the discontinuance of hedge accounting for non-Appalachian E&P gas and oil derivatives during 2007.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in our Combined Balance Sheet at December 31, 2009:

 

		AOCI After-tax			Amounts expected to be reclassified to earnings during the next 12 months After-tax			Maximum Term
(thousands)
Commodities
Gas		$	28,905		$	27,044		24 months

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices.

 

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Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of our derivatives at December 31, 2009 and where they are presented on our Combined Balance Sheet:

 

		Fair Value- Derivatives under Hedge Accounting			Fair Value- Derivatives not under Hedge Accounting			Total Fair Value
(thousands)
Assets
Current Assets
Commodity		$	45,447		$	208		$	45,655
Noncurrent Assets
Commodity			3,131			—			3,131
Total Affiliated Derivative Assets			48,578			208			48,786
Liabilities
Current Liabilities
Commodity(1)		$	—		$	208		$	208

 

(1)	Current derivative liabilities are presented in other current liabilities on our Combined Balance Sheet.

The following tables present the gains and losses on our derivatives, as well as where the associated activity is presented on our Combined Balance Sheet and Statement of Income at December 31, 2009:

 

Derivatives in cash flow hedging relationships		Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified from AOCI into Income
(thousands)
Derivative Type and Location of Gains (Losses)
Commodity(2)		$	92,451		$	134,262

 

(1)	Amounts deferred into AOCI have no associated effect in our Combined Statement of Income.

(2)	Amounts recorded in our Combined Statement of Income are classified in operating revenue.

 

Derivatives not designated as hedging instruments		Amount of Gain (Loss) Recognized in Income on Derivatives
(thousands)
Derivative Type and Location of Gains (Losses)
Commodity(1)		$	1,316

 

(1)	Amounts recorded in our Combined Statement of Income are classified in operating revenue.

Note 9. Property, Plant and Equipment

There were no significant properties under development, as defined by the SEC, excluded from amortization at December 31, 2009 and 2008. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.

Volumetric Production Payment Transactions

We previously entered into VPP transactions in which cash proceeds received were recorded as deferred revenue. We recognized revenue as natural gas was produced and delivered to the purchaser. During 2007, in

 

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conjunction with the sales of our non-Appalachian E&P operations, we paid approximately $250 million to terminate the agreements on behalf of the Companies as well as other Dominion affiliates, and another Dominion affiliate assumed the VPP royalty interests formerly associated with these agreements. We received approximately $230 million for this conveyance of mineral interests under the terms of a new VPP agreement with an affiliated company.

Assignment of Marcellus Acreage

In 2008, we completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. We received proceeds of approximately $347 million and recognized $4 million of associated closing costs. The net proceeds were credited to our full cost pool, reducing property, plant and equipment in the Combined Balance Sheet, as the transaction did not significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil. Under the agreement, we receive a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. We retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continue our conventional drilling program on the acreage.

Sale of E&P Properties

In 2007, we sold our non-Appalachian natural gas and oil E&P operations and assets for approximately $7 billion, which included the sale of a portion of our full cost pool. In 2009, we sold certain oil and gas leases to unrelated third parties for approximately $22 million. See Note 4 for additional information.

Note 10. Asset Retirement Obligations

Our AROs are primarily associated with plugging and abandonment of gas and oil wells. These obligations result from certain safety and environmental activities we are required to perform when any well is abandoned.

The changes to our AROs during 2009 were as follows:

 

		Amount
(thousands)
Asset retirement obligation at December 31, 2008(1)		$	114,839
Liabilities incurred			1,626
Obligations settled			(112	)
Revisions in estimated cash flows			—
Accretion expense			5,786
Other			448
Asset retirement obligation at December 31, 2009		$	122,587

 

(1)	Includes approximately $1 million reported in other current liabilities at December 31, 2008. There were no amounts reported in other current liabilities at December 31, 2009.

Note 11. Short-Term Debt and Credit Agreements

We use affiliated current borrowings to fund working capital requirements, as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations.

 

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Note 12. Long-Term Debt

 

At December 31,		2009 Weighted- average Coupon(1)			2009			2008
(thousands)
Notes payable to affiliates, 6.8% to 8.95%, due 2013 to 2017		7.20	%		$	3,530		$	5,460
Notes payable to affiliates, 6.45%, due 2017		6.45	%			525,000			525,000
Total long-term debt					$	528,530		$	530,460

 

(1)	Represents weighted-average coupon rates for debt outstanding as of December 31, 2009.

Based on stated maturity dates, the scheduled principal payments of long-term debt at December 31, 2009 were as follows:

 

		2010			2011			2012			2013			2014			Thereafter			Total
(thousands)
		$	—		$	—		$	—		$	1,404		$	1,043		$	526,083		$	528,530

Note 13. Employee Benefit Plans

The Companies participate in defined benefit pension plans sponsored by Dominion and DTI. Benefits payable under the plans are based primarily on years of service, age and the employee’s compensation. As a participating employer, the Companies are subject to Dominion’s and DTI’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. The Companies’ net periodic benefit credit related to the plans was approximately $3 million, $4 million and $3 million in 2009, 2008, and 2007, respectively. Employee compensation is the basis for determining the Companies’ share of total pension costs. The Companies did not contribute to the pension plans in 2009, 2008, or 2007.

The Companies participate in Dominion and DTI plans that provide certain retiree health care and life insurance benefits. Annual employee premiums are based on several factors such as age, retirement date and years of service. The Companies’ net periodic benefit cost related to the plans was $2 million, $2 million and $13 million in 2009, 2008 and 2007, respectively. Employee headcount is the basis for determining the Companies’ share of total benefit costs.

The Companies also participate in Dominion-sponsored employee savings plans that cover substantially all employees. Employer matching contributions of $0.8 million, $0.7 million and $2 million were incurred in 2009, 2008 and 2007, respectively.

Note 14. Commitments and Contingencies

As the result of issues generated in the ordinary course of business, we are involved in legal and tax proceedings before various courts and governmental agencies, some of which involve substantial amounts of money. The ultimate outcome of these proceedings cannot be predicted at this time; however, we believe that the final disposition of these proceedings will not have a material effect on our financial position, liquidity or results of operations.

Lease Commitments

We lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments

 

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under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2009 are as follows:

 

		2010			2011			2012			2013			2014			Thereafter			Total
(thousands)
		$	741		$	974		$	795		$	737		$	667		$	1,161		$	5,075

Rental expense totaled $3 million, $3 million, and $11 million in 2009, 2008, and 2007 respectively, all of which is reflected in general and administrative expense.

Environmental Matters

We are subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations and can result in increased capital, operating and other costs as a result of our compliance, remediation, containment and monitoring obligations.

In June 2009, the U.S. House of Representatives passed comprehensive legislation titled the “American Clean Energy and Security Act of 2009” to encourage the development of clean energy sources and reduce greenhouse gas (GHG) emissions. The legislation includes cap-and-trade provisions for the reduction of GHG emissions. Similar legislation has been introduced in the U.S. Senate. In addition, the Environmental Protection Agency (EPA) has proposed one rule and finalized another rule that together hold that GHGs are air pollutants subject to the provisions of the Clean Air Act. These are the EPA Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act and the Proposed Rulemaking To Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards (proposed September 2009). Possible outcomes from these actions include regulation of GHG emissions from various sources, including gas operations facilities. We are unable to determine the impact from these actions on our gas facilities that emit GHGs at this time.

Surety Bonds

As of December 31, 2009, we had purchased $6 million of surety bonds to facilitate commercial transactions with third parties.

Indemnifications

As part of commercial contract negotiations in the normal course of business, we may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. We are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate us have not yet occurred or, if any such event has occurred, we have not been notified of its occurrence. However, at December 31, 2009, we believe that future payments, if any, which could ultimately become payable under these contract provisions, would not have a material impact on our results of operations, cash flows or financial position.

Litigation

We have been involved in litigation since 2006 with certain royalty owners seeking to recover damages as a result of our allegedly underpaying royalties by improperly deducting post-production costs and not paying fair market value for the gas produced from their leases. The plaintiffs sought class action status on behalf of all West Virginia residents and others who are parties to, or beneficiaries of, oil and gas leases with us. In 2008, the

 

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Court preliminarily approved settlement of the class action and conditionally certified a temporary settlement class. Following preliminary approval by the Court, settlement notices were sent out to potential class members. In 2009, the Court entered a Memorandum Opinion and Final Order approving settlement and certifying the settlement class and the Final Judgment Order. In 2007, we established a litigation reserve representing our best estimate of the probable loss related to this matter. As of December 31, 2009, the remaining liability was $15 million, of which $2 million was reserved in escrow. We do not believe that final resolution of the matter will have a material adverse effect on our results of operations or financial condition.

We are currently involved in settlement negotiations for litigation alleging that oil and gas severance tax refunds have not been properly redistributed to royalty owners and non-operating working interest owners in Texas and New Mexico. We are also one of approximately 20 defendants and a member of a joint defense group that shares expert witness and other litigation costs concerning the calculation of royalty payments on gas produced from federal leases during 1995-1999. We have agreed to the terms of a settlement and are working on finalizing the details. As of December 31, 2009, reserves were established for these matters totaling approximately $6 million. We do not believe that final resolution of these matters will have a material adverse effect on our results of operations or financial condition.

Note 15. Credit Risk

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. We sell natural gas and oil produced from our reserves primarily to affiliated companies as well as third parties. These transactions principally occur in the Appalachian basin region of the United States. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk.

Our exposure to potential concentrations of credit risk results primarily from sales to major companies in the energy industry. We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers. At December 31, 2009, no single non-affiliated party represented more than 3% of the gross receivables balance. As a result, we believe that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

Note 16. Related Party Transactions

We engage in related party transactions primarily with affiliates (Dominion subsidiaries). Our accounts receivable and payable balances with affiliates are settled based on contractual terms on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion and DTI benefit plans.

Transactions with Affiliates

We transact with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. We also enter into certain financial derivative commodity contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with the sale of natural gas. We designate the majority of these contracts as cash flow hedges for accounting purposes.

The following table presents derivative asset and liability positions with affiliates:

 

At December 31,		2009			2008
(thousands)
Derivative assets		$	48,786		76,987
Derivative liabilities			208		—

 

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Presented below are affiliated transactions, including net realized gains and losses recorded in operating revenue and operating expenses:

 

Year Ended December 31,		2009			2008				2007
(thousands)
Sales to affiliates		$	189,841		$	365,305			$	302,827
Settlements of commodity derivative contracts with affiliates			108,758			(3,398	)			112,808
Purchases from affiliates			—			—				39,664

Dominion Resources Services (Dominion Services) and other affiliates provide certain administrative and technical services to us. The cost of services provided to us by Dominion Services and other affiliates is as follows:

 

Year Ended December 31,		2009			2008			2007
(thousands)
Cost of services provided by Dominion Services		$	15,836		$	18,929		$	51,366
Cost of services provided by other affiliates			3,812			4,046			2,905

As disclosed in Note 12, Dominion E&P has long-term debt with affiliates. See Note 12 for information regarding Dominion E&P’s long-term debt, expected maturities, and related principal payments. Dominion E&P incurred interest charges related to affiliates of $35 million, $52 million, and $81 million in 2009, 2008 and 2007, respectively. Dominion E&P earned interest income related to affiliates of $15 million and $39 million in 2008 and 2007, respectively. We earned no interest income related to affiliates in 2009.

At December 31, 2009, Dominion E&P’s Combined Balance Sheet included a $3 million receivable from Dominion for refundable federal income taxes and a $10 million liability for state income taxes payable to Dominion. Dominion E&P’s Combined Balance Sheet at December 31, 2008, included a $29 million receivable from Dominion for refundable federal income taxes and a $26 million liability for state income taxes payable to Dominion.

Note 17. Subsequent Events

We have evaluated subsequent events through March 14, 2010, which is the date the financial statements were available to be issued.

In March 2010, the expected sale of our Appalachian E&P operations resulted in the discontinuance of hedge accounting for our cash flow hedges since it will become probable that the forecasted sales of gas will not occur. In connection with the discontinuance of hedge accounting for these contracts, we will recognize gains for a substantial portion of our derivative balance, reflecting the reclassification of gains from AOCI to earnings.

 

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Note 18. Gas & Oil Producing Activities (unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depletion follow:

 

At December 31,		2009			2008
(thousands)
Capitalized costs:
Proved properties		$	1,668,586		$	1,515,633
Unproved properties			8,416			10,838
Total capitalized costs			1,677,002			1,526,471
Accumulated depletion:
Proved properties			674,129			327,169
Unproved properties			—			—
Total accumulated depletion			674,129			327,169
Net capitalized costs		$	1,002,873		$	1,199,302

Total Costs Incurred

The following costs were incurred in gas and oil producing activities:

 

Year Ended December 31,		2009			2008			2007
(thousands)
Property acquisition costs:
Proved properties		$	238		$	2,297		$	7,113
Unproved properties			1,711			3,738			32,456
Total property acquisition costs			1,949			6,035			39,569
Exploration costs			854			1,235			112,004
Development costs(1)			159,382			205,578			482,721
Total		$	162,185		$	212,848		$	634,294

 

(1)	Development costs incurred for proved undeveloped reserves were $133 million, $80 million and $445 million for 2009, 2008 and 2007, respectively.

Company-Owned Reserves

The preparation of our gas reserve estimates is completed in accordance with the Companies’ prescribed internal control procedures, which include verification of input data into a reserve forecasting and economic evaluation software as well as management review. The technical employee responsible for overseeing the preparation of the reserve estimates is an oil and gas engineer. Our 2009 oil and gas reserve results were audited by Ryder Scott Company. The technical person primarily responsible for overseeing the audit of our reserves is a certified oil and gas engineer.

 

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Estimated net quantities of proved gas and oil (including condensate) reserves at December 31, 2009, 2008 and 2007, and changes in the reserves during those years, are shown in the schedules that follow:

 

		2009			2008			2007
Proved developed and undeveloped reserves—Gas
(bcf)
At January 1		1,097			999			1,895
Changes in reserves:
Extensions, discoveries and other additions		49			46			23
Revisions of previous estimates		69			93			90
Production		(45	)		(41	)		(92	)
Purchases of gas in place		—			—			10
Sales of gas in place		—			—			(927	)
At December 31		1,170			1,097			999
Proved developed and undeveloped reserves—Oil
(thousands of barrels)
At January 1		12,434			12,613			96,133
Changes in reserves:
Extensions, discoveries and other additions		892			484			29
Revisions of previous estimates		2,401			256			907
Production		(942	)		(919	)		(8,106	)
Purchases of oil in place		1			—			—
Sales of oil in place		—			—			(76,350	)
At December 31(1)		14,786			12,434			12,613

 

(1)	Ending reserves for 2009, 2008 and 2007 included 1.2 million, 1.0 million and 0.3 million barrels of oil/condensate, respectively, and 13.6, 11.4 and 12.3 million barrels of natural gas liquids, respectively.

 

Proved developed reserves as of December 31,		Gas (bcf)		Oil (bbl)		Equivalent Total (bcf)
2009		748		14,571		835
2008		670		12,406		744
2007		616		12,613		692
2006		1,212		87,887		1,740

 

Proved undeveloped reserves as of December 31,		Gas (bcf)		Oil (bbl)		Equivalent Total (bcf)
2009		422		215		424
2008		427		28		427
2007		383		—		383
2006		683		8,246		733

Approximately $47 million of capital was spent in the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.

 

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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The following tabulation has been prepared in accordance with the FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities that we own:

 

		2009			2008			2007
(thousands)
Future cash inflows(1)		$	4,949,811		$	7,359,788		$	8,128,335
Less:
Future development costs(2)			780,214			919,968			671,384
Future production costs			1,314,691			1,293,347			1,234,783
Future income tax expense			1,046,694			2,009,900			2,431,572
Future cash flows			1,808,212			3,136,573			3,790,596
Less annual discount (10% a year)			1,221,798			2,029,024			2,346,754
Standardized measure of discounted future net cash flows		$	586,414		$	1,107,549		$	1,443,842

 

(1)	Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year-end.

(2)	Estimated future development costs, excluding abandonment, for proved undeveloped reserves are estimated to be $126 million, $97 million and $68 million for 2010, 2011 and 2012, respectively.

In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of our proved reserves. We caution that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

 

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The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year:

 

		2009				2008				2007
(thousands)
Standardized measure of discounted future net cash flows at January 1		$	1,107,549			$	1,443,842			$	4,600,249
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs			(191,974	)			(460,307	)			(732,213	)
Prices and production and development costs related to future production			(953,983	)			(720,764	)			288,780
Extensions, discoveries and other additions, less production and development costs			72,638				128,600				53,722
Previously estimated development costs incurred during the year			132,839				67,000				235,655
Revisions of previous quantity estimates			(36,748	)			170,733				249,049
Accretion of discount			185,178				236,117				180,670
Income taxes			273,181				119,329				1,111,950
Other purchases and sales of proved reserves in place			101				345				(4,530,255	)
Other (principally timing of production)			(2,367	)			122,654				(13,765	)
Standardized measure of discounted future net cash flows at December 31		$	586,414			$	1,107,549			$	1,443,842

 

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PROSPECTUS

Consol Energy Inc.

Common Stock, Preferred Stock, Debt Securities,

Warrants, Purchase Contracts, Units and Depository Shares

We may offer from time to time common stock, preferred stock, debt securities, warrants, purchase contracts, units or depository shares. In addition, certain selling securityholders to be identified in a prospectus supplement may offer and sell these securities from time to time, in amounts, at prices and on terms that will be determined at the time the securities are offered. We urge you to read this prospectus and any accompanying prospectus supplement, together with the documents we incorporate by reference, which will describe the specific terms of these securities, carefully before you make your investment decision.

Our common stock is listed on the New York Stock Exchange under the trading symbol “CNX.”

Investing in these securities involves certain risks. See “Risk Factors” on page 2 of this prospectus and in the other documents which are incorporated by reference herein.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is May 30, 2008.

 

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TABLE OF CONTENTS

 

		Page
About this Prospectus		1
CONSOL Energy Inc.		1
Risk Factors		2
Forward-Looking Information		15
Use of Proceeds		18
Ratio of Earnings to Fixed Charges		18
Description of Securities		19
Description of CONSOL Energy Capital Stock		19
Description of Debt Securities		23
Description of Warrants		23
Description of Purchase Contracts		23
Description of Units		24
Description of Depositary Shares		24
Forms of Securities		24
Plan of Distribution		26
Where You Can Find More Information		27
Experts		29

 

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ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or the SEC, utilizing a “shelf” registration process. Under this shelf process, we may sell any combination of the securities described in this prospectus in one or more offerings. This prospectus provides you with a general description of the securities we may offer. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read both this prospectus and any prospectus supplement together with additional information described under the heading “Where You Can Find More Information.”

We have filed or incorporated by reference exhibits to the registration statement of which this prospectus forms a part. You should read the exhibits carefully for provisions that may be important to you.

Except as otherwise specifically noted, “we,” “our,” “us” and similar words and/or “CONSOL” or “CONSOL Energy” in this prospectus refer to CONSOL Energy Inc.

CONSOL ENERGY INC.

CONSOL Energy Inc., a high-Btu bituminous coal and coal bed methane company, is a member of the Standard & Poor’s 500 Equity Index and has annual revenues of $3.8 billion. It has 17 bituminous coal mining complexes in six states and reports proven and probable coal reserves of 4.5 billion tons. CONSOL Energy was named one of America’s most admired companies in 2005 by Fortune magazine. It received the U.S. Department of the Interior’s Office of Surface Mining National Award for Excellence in Surface Mining for the company’s innovative reclamation practices in 2002, 2003 and 2004. Also in 2003, the company was listed in Information Week magazine’s “Information Week 500” list for its information technology operations. In 2002, the company received a U.S. Environmental Protection Agency Climate Protection Award.

CONSOL Energy Inc. was organized as a Delaware corporation in 1991. The principal executive office of CONSOL Energy Inc. is located at CONSOL Plaza, 1800 Washington Road, Pittsburgh, Pennsylvania, 15241, and the telephone number at that address is (412) 831-4000. Our website is located at www.consolenergy.com. The information on our website is not part of this prospectus.

 

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RISK FACTORS

Investing in our securities will be subject to risks, including risks inherent in our business. The value of your investment may decline and could result in a loss. You should carefully consider the following factors as well as other information contained and incorporated by reference in this prospectus and in the accompanying prospectus supplement before deciding to invest in our securities:

RISKS RELATED TO OUR BUSINESS

Our business activities are subject to hazards and risks. The following is a summary of the material risks relating to our business activities. You should carefully consider the material risks described below, as well as the other information contained in this prospectus and the documents incorporated by reference in this prospectus under the caption “Where You Can Find More Information” beginning on page 27. If any of the events described below occur, our business, financial condition and/or results of operations could be materially harmed, and you could lose part or all of your investment.

A significant extended decline in the prices CONSOL receives for our coal and gas could adversely affect our operating results and cash flows.

CONSOL’s results of operations are highly dependent upon the prices we receive for our coal, which are closely linked to consumption patterns of the electric generation industry and certain industrial and residential patterns where gas is the principal fuel. Extended or substantial price declines for coal would adversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. Prices of coal may fluctuate due to factors beyond our control such as overall domestic and global economic conditions; the consumption pattern of industrial consumers, electricity generators and residential users; technological advances affecting energy consumption; domestic and foreign government regulations; price and availability of alternative fuels; price of foreign imports and weather conditions. Any adverse change in these factors could result in weaker demand and possibly lower prices for our production, which would reduce our revenues.

Natural gas prices are volatile, and even relatively modest drops in prices can significantly affect our financial results and impede growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. If we choose not to engage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging arrangements to a greater extent than we do. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as: the domestic and foreign supply of natural gas; the price of foreign imports; overall domestic and global economic conditions; the consumption pattern of industrial consumers, electricity generators and residential users; weather conditions; technological advances affecting energy consumption; domestic and foreign governmental regulations; proximity and capacity of gas pipelines and other transportation facilities; and the price and availability of alternative fuels. Many of these factors may be beyond our control. Earlier in this decade, natural gas prices were lower than they are today. Lower natural gas prices may not only decrease our revenues on a per unit basis, but may also limit our access to capital. A significant decrease in price levels for an extended period would negatively affect us in several ways including our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production; and access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of

 

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development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

If customers do not extend existing contracts or do not enter into new long-term contracts for coal, profitability of CONSOL’s operations could be affected.

During the year ended December 31, 2007, approximately 90% of the coal CONSOL produced was sold under long-term contracts (contracts with terms of one year or more). If a substantial portion of CONSOL’s long-term contracts are modified or terminated or if force majeure is exercised, CONSOL would be adversely affected if we are unable to replace the contracts or if new contracts were not at the same level of profitability. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, CONSOL 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, 2007, we derived over 25% of our total revenues from sales to our four largest coal customers. At December 31, 2007, we had approximately 16 coal supply agreements with these customers that expire at various times from 2008 to 2021. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us under long-term coal supply agreements. If any one of these four customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.

Our ability to collect payments from our customers could be impaired if their creditworthiness declines.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base has changed with deregulation as some utilities sold their power plants to their non-regulated affiliates or third parties. These new power plant owners may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly, our $165 million accounts receivable securitization program and our business could be adversely affected.

Disruption of rail, barge, overland conveyor and other systems that deliver CONSOL’s coal, or an increase in transportation costs could make CONSOL’s coal less competitive.

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.

 

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Competition within the coal and gas industries may adversely affect our ability to sell our products, or a loss of our competitive position because of overcapacity in these industries could adversely affect pricing which could impair our profitability.

CONSOL competes with coal producers in various regions of the United States and with some foreign coal producers for domestic sales primarily to power generators. CONSOL also competes with both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power. CONSOL 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.

Recent increases in coal prices could encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could affect our ability to sell coal or reduce coal prices and therefore reduce our revenues.

The gas industry is intensely competitive with companies from various regions of the United States and we may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our operating results and financial position may be adversely affected. For example, one of our competitive strengths is being a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive strength in that area. In addition, larger companies may be able to pay more to acquire new gas properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new gas resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

We require a skilled workforce to run our business. If we cannot hire qualified people to meet replacement or expansion needs, we may not be able to achieve planned results.

Most of our workforce is comprised of people with technical skills related to the production of coal and gas. Approximately 55 percent of our workforce is 50 years of age or older. Based on our experience, we expect a high percentage of our employees to retire between now and the next five to seven years. This will require us to conduct an expanded and sustained effort to recruit new employees to replace those who retire and to fill new jobs as we grow our business. Some areas of Appalachia, most notably in eastern Kentucky, currently have a shortage of skilled labor. Because we have operations in this area, the shortage could make it more difficult to meet our staffing needs and therefore, our results may be adversely affected. Finally, a lack of qualified people may also affect companies that we use to perform certain specialized work. If these companies cannot find enough qualified workers, it may delay projects done for us or increase our costs.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards, which are continually under review by international, federal and state agencies, related to coal combustion. As a result, they may switch to other fuels, which would affect the volume of CONSOL’s sales.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fired electric generating plants could increase the costs of using coal thereby reducing demand for coal as a fuel source, the volume of our coal sales and price. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future.

For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of

 

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installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which power generators switch to alternative fuel could materially affect us if we cannot offset the cost of sulfur removal by lowering the delivered costs of our higher sulfur coals on an energy equivalent basis.

Recently adopted regulations requiring reductions in emissions of sulfur dioxides, nitrogen oxides and particulate matter are likely to require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. Also, on February 8, 2008, recently adopted mercury regulations were vacated by the U.S. Court of Appeals for the District of Columbia. EPA is evaluating the opinion and considering its impacts. The recently adopted regulations for sulfur dioxides, nitrogen oxides and particulate matter and any new regulations for mercury will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative to the planning and building of utility power plants in the future. To the extent that any new or proposed requirements affect our customers, this could adversely affect our operations and results.

CONSOL may not be able to produce sufficient amounts of coal to fulfill our customers’ requirements, which could harm our relationships with customers.

CONSOL may not be able to produce sufficient amounts of coal to meet customer demand, including amounts that we are required to deliver under long-term contracts. CONSOL’s inability to satisfy contractual obligations could result in our customers initiating claims against us.

Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We compete in international markets against coal produced in other countries. Coal is sold internationally in U. S. dollars. As a result, mining costs in competing producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. Currency fluctuations among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.

Coal mining is subject to conditions or events beyond CONSOL’s control, which could cause our financial results to deteriorate.

CONSOL’s coal mining operations are predominantly underground mines. These mines are subject to conditions or events beyond CONSOL’s control that could disrupt operations and affect production and the cost of mining at particular mines for varying lengths of time. These conditions or events may have a significant impact on our operating results. Conditions or events have included:

 

•

variations in thickness of the layer, or seam, of coal;

 

•

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;

 

•

equipment failures or repairs;

 

•

fires and other accidents; and

 

•

weather conditions.

Our mining operations consume significant quantities of commodities, the price of which is determined by international markets. If commodity prices increase significantly or rapidly, it could impact our cost of production.

Coal mines consume large quantities of commodities such as steel, copper, rubber products and liquid fuels. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for these products are strongly impacted by the global commodities market. A rapid or significant

 

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increase in cost of some commodities could impact our mining costs because we have a limited ability to negotiate lower prices, and, in some cases, do not have a ready substitute for these commodities.

CONSOL must obtain for mining and drilling operations, governmental permits and approvals which can be a costly and time consuming process and can result in restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of exploration or production operations. For example, CONSOL often is required to prepare and present to federal, state and local authorities data pertaining to the effect or impact that proposed exploration for or production of coal may have on the environment. Further, the public has the right to comment on and otherwise participate in the permitting process, including through administrative appeals of permits and possibly further appeals in the courts. Accordingly, the permits CONSOL needs may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements which restrict our ability to conduct our mining or gas operations or to do so profitably.

Proposals to regulate greenhouse gas emissions could impact the market for our fossil fuels, increase our costs, and reduce the value of our coal and gas assets.

Numerous proposals have been made at the international, national, regional, and state levels of government that are intended to limit emissions of greenhouse gas (GHGs), such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal and gas we produce results in the creation of carbon dioxide that is currently emitted into the atmosphere by coal and gas end users. Several states have already adopted measures requiring reduction of GHGs within state boundaries. If comprehensive regulations focusing on GHGs emission reductions were to be enacted by the United States or additional individual states, it may adversely affect the use of and demand for fossil fuels, particularly coal. Further regulation of GHGs could occur in the United States pursuant to treaty obligations, regulation under the Clean Air Act, or regulation under state law. In 2007, the U.S. Supreme Court held in Massachusetts v. Environmental Protection Agency (EPA), that EPA had authority to regulate GHGs under the Clean Air Act, reversing the EPA’s interpretation of the Act. This decision could lead to federal regulation of GHGs under the existing Clean Air Act of coal-fired electric generation stations, which could adversely affect demand for our products.

In addition, many of our underground coal mines vent methane into the atmosphere for safety reasons. Coal bed methane enhances the greenhouse gas effect to a greater degree than carbon dioxide. If regulation of GHG emissions does not exempt coal mine methane, we may have to curtail production, pay higher taxes, or incur costs to purchase allowances that permit us to continue operations as they now exist.

Our gas operations primarily produce gas by capturing coal bed methane. If the coal bed methane is not extracted from the coal seam prior to mining, much of this gas would be liberated to the atmosphere when the coal is mined. The coal bed methane we capture is recorded, on a voluntarily basis, with the U.S Department of Energy. We have recorded the amounts we have captured since the early 1900’s. If regulation of GHGs does not give us credit for methane that would otherwise be released into the atmosphere, any value associated with our historical or future credits would be reduced or eliminated.

In addition, on February 4, 2008 three of Wall Street’s largest investment banks announced that they had adopted climate change guidelines for lenders to evaluate carbon risks in the financing of utility power plants which may make it more difficult for utilities to obtain financing for coal-fired plants.

Government laws, regulations and other legal requirements relating to protection of the environment, health and safety matters and others that govern our business increase our costs of doing business for both coal and gas, and may restrict our operations.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment and health and safety matters,

 

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including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in our mines, control of surface subsidence from underground mining and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position. In addition, we could incur substantial costs, including clean up costs, fines and civil or criminal sanctions and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a result of violations of or liabilities under environmental and health and safety laws.

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. In combination with existing requirements, new requirements under the Clean Water Act and corresponding state laws (including those relating to protection of “impaired waters” so designated by individual states through the use of new effluent limitations known as Total Maximum Daily Load (“TMDL”) limits; anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting “discharges” which result in degradation; and requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides and selenium; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from the surface impacts of underground mining), may cause CONSOL to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows or may prevent us from being able to mine portions of our reserves. In addition, CONSOL incurs and will continue to incur significant costs associated with the investigation and remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past.

Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.

Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations, and may place restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shut down based on safety considerations.

Stringent health and safety standards were imposed by federal legislation when the Federal Coal Mine Health and Safety Act of 1969 was adopted. The Federal Coal Mine Safety and Health Act of 1977 expanded the enforcement of safety and health standards of the Coal Mine Health and Safety Act of 1969 and imposed safety and health standards on all (non-coal as well as coal) mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mine emergency procedures, mine plans and other matters. Several mining accidents at our competitors’ mines that resulted in fatalities in early 2006 led to adoption of additional safety regulations by the Mine Safety and Health Administration and the adoption in June 2006 of the Mine Improvement and New Emergency Response Act of 2006 (“the MINER Act”). The additional requirements of 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

 

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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 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 have a significant effect on operating costs and place restrictions on our methods of operations. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shut down based on safety considerations.

CONSOL has reclamation and mine closure 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. CONSOL accrues for the costs of current mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities, which are based upon permit requirements and our experience were approximately $482 million at December 31, 2007. The amounts 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 rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.

CONSOL faces uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

There are uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff.

Some of the factors and assumptions which impact economically recoverable reserve estimates include:

 

•

geological conditions;

 

•

historical production from the area compared with production from other producing areas;

 

•

the assumed effects of regulations and taxes by governmental agencies;

 

•

assumptions governing future prices; and

 

•

future operating costs, including cost of materials.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual reserves.

We do not insure against all potential operating risks. We may incur losses and be subject to liability claims as a result of our operations.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive

 

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relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.

Fairmont Supply Company, a subsidiary of CONSOL, 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 25,000 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi and New Jersey. 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 year ended December 31, 2007, payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOL. 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.

CONSOL and its subsidiaries are subject to various legal proceedings, which may have a material effect on our business.

We are party to a number of legal proceedings incident to normal business activities. There is the potential that an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position. See Note 26 of Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007 for further discussion.

CONSOL has obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in CONSOL being required to expense greater amounts than anticipated.

CONSOL provides various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2007, the current and non-current portions of these obligations, included:

 

•

post retirement medical and life insurance ($2.5 billion);

 

•

coal workers’ black lung benefits ($182.9 million);

 

•

salaried retirement benefits ($70.2 million); and

 

•

workers’ compensation ($162.1 million).

However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. These obligations are unfunded, except for salaried retirement benefits, of which approximately 90%

 

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was funded at December 31, 2007. In addition, 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 multi-employer pension and benefit plans, we have exposure under those plans that extend beyond what our obligation would be with respect to our employees.

We are obligated to contribute to multi-employer defined benefit plans for UMWA retirees which provide pension, medical and death benefits. In the event of a partial or complete withdrawal by us from any plan which is underfunded, we would be liable for a proportionate share of such plan’s unfunded vested benefits. Based on the limited information available from plan administrators, which we cannot independently validate, we believe that our portion of the contingent liability in the case of a full withdrawal or termination could be material to our financial position and results of operations. In the event that any other contributing employer withdraws from any plan which is underfunded, 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 our proportionate share of such plan’s unfunded vested benefits.

In addition, if a multi-employer pension plan fails to satisfy the minimum funding requirements, the Internal Revenue Service, pursuant to Section 4971 of the Internal Revenue Code (the “Code”) will impose an excise tax of 5% on the amount of the accumulated funding deficiency. Under Section 413(c)(5) of the Code, the liability of each contributing employer, including us, will be determined in part by each employer’s additional contributions in order to reduce the deficiency to zero, which may, along with the payment of the excise tax, have a material adverse impact on our financial results.

If lump sum payments made to retiring salaried employees pursuant to CONSOL’s defined benefit pension plan exceed the total of the service cost and the interest cost in a plan year, CONSOL would need to make an adjustment to operating results equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum payment in that year, which may result in an adjustment that could materially reduce operating results.

CONSOL’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. Statement of Financial Accounting Standards No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for the Terminations Benefits,” requires that if the lump-sum distributions made for a plan year, which currently for CONSOL is October 1 to September 30, exceed the total of the service cost and interest cost for the plan year, CONSOL 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. Lump sum payments in CONSOL’s non-qualified pension plan exceeded the total of the service cost and the interest cost in the plan year ended September 30, 2007. This resulted in expense of $2.7 million in the year ended December 31, 2007. If lump sum payments again exceed the total of the service cost and the interest cost, the adjustment could materially reduce operating results.

Various federal or state laws and regulations require CONSOL to obtain surety bonds or to provide other assurance of payment for certain of our long-term liabilities including mine closure or reclamation costs, workers’ compensation, coal workers’ black lung and other post employment benefits.

Federal and state laws and regulations require us to obtain surety bonds or provide other assurances to secure payment of certain long-term obligations including mine closure or reclamation costs, water treatment costs, federal and state workers’ compensation costs, and other miscellaneous obligations. The requirements and amounts of security are not fixed and can vary from year to year. It has become increasingly difficult for us to secure new surety bonds or renew such bonds without posting collateral. CONSOL has satisfied our obligations under these statutes and regulations by providing letters of credit or other assurances of payment. The issuance of letters of credit under our bank credit facility reduces amounts that we can borrow under our bank credit facility for other purposes.

 

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Acquisitions that we have completed, as well as acquisitions that we may undertake in the future, involve a number of risks, any of which could cause us not to realize the anticipated benefits.

We have completed several acquisitions and investments in the past. We continually seek to expand our operations and coal and gas reserves through acquisitions. If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Acquisition transactions involve various inherent risks, including:

 

•

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 acquisition candidates;

 

•

The potential loss of key customers, management and employees of an acquired business;

 

•

The ability to achieve identified operating and financial synergies anticipated to result from an acquisition;

 

•

Problems that could arise from the integration of the acquired business; and

 

•

Unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the acquisition.

CONSOL’s rights plan may have anti-takeover effects that could prevent a change of control.

On December 19, 2003, CONSOL 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 common stock, would entitle each right holder to receive, upon exercise of the right, shares of CONSOL 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 common stock for $80. Assuming that shares of CONSOL 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 common stock for $80, or a price of $8 per share, one half its then market price. This and other provisions of CONSOL’s rights plan could make it more difficult for a third party to acquire CONSOL, which could hinder stockholders’ ability to receive a premium for CONSOL stock over the prevailing market prices.

CONSOL faces uncertainties in estimating proved recoverable gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.

Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and timing of development expenditures may be incorrect. We have in the past retained the services of independent petroleum engineers to prepare reports of our proved reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing, and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash

 

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flows from our proved reserves on prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:

 

•

geological conditions;

 

•

changes in governmental regulations and taxation;

 

•

assumptions governing future prices;

 

•

the amount and timing of actual production;

 

•

future operating costs; and

 

•

capital costs of drilling new wells.

The timing of both our production and 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.

Our gas exploration and development activities may not be commercially successful.

The exploration for and production of gas involves risks. The cost of drilling, completing and operating wells for coal bed methane or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

 

•

unexpected drilling conditions;

 

•

title problems;

 

•

pressure or irregularities in geologic formations;

 

•

equipment failures or repairs;

 

•

fires or other accidents;

 

•

adverse weather conditions;

 

•

reductions in natural gas prices;

 

•

pipeline ruptures; and

 

•

unavailability or high cost of drilling rigs, other field services and equipment.

Our future drilling activities may not be successful, and our drilling success rate could decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues.

We have a limited operating history in certain of our gas operating areas, and our increased focus on new development projects in these and other unexplored areas increases the risks inherent in our gas and oil activities.

In 2008 and beyond we plan to conduct testing and development activities in areas where we have little or no proved reserves, such as certain areas in Pennsylvania and Kentucky. These exploration, drilling and production activities will be subject to many risks, including the risk that coal bed methane or natural gas is not present in sufficient quantities in the coal seam or target strata, or that sufficient permeability does not exist for gas to be produced economically. We have invested in property, and will continue to invest in property, including undeveloped leasehold acreage, that we believe will result in projects that will add value over time. Drilling for coal bed methane, natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling,

 

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operating and other costs. We cannot be certain that the wells we drill in these new areas will be productive or that we will recover all or any portion of our investments.

Our gas business depends on transportation facilities owned by others. Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our gas.

We transport our gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, reducing our profitability. If we cannot access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. If our sales are reduced because of transportation constraints, our revenues will be reduced, which will also increase our unit costs. If we cannot obtain transportation capacity and we do not have the ability to store gas, we may have to reduce production. If pipeline quality tariffs change, we might be required to install additional processing equipment which could increase our costs. The pipeline could curtail our flows until the gas delivered to the pipeline is in compliance.

Increased gas industry activity may create shortages of field services, equipment and personnel, which may increase our costs and may limit our ability to drill and produce gas.

Due to current industry demands, well service providers and related equipment are in short supply. The demand for qualified and experienced field personnel to drill wells and conduct field operations, including, geologists, geophysicists, engineers and other professionals, in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These shortages may lead to escalating prices, the possibility of poor services, ineffective drilling operations and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. We believe that these shortages could continue. In addition, the costs and delivery time of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.

Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2007, 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.

We may incur additional costs and delays to produce gas because we have to acquire additional property rights to perfect our title to the gas estate.

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. Most of these properties were acquired primarily for the coal rights, and, in many cases were

 

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acquired years ago. While chain of title work for the coal estate was generally fully developed, in many cases, the gas estate title work is less robust. Our practice is to perform a thorough title examination of the gas estate before we commence drilling activities and to acquire any additional rights needed to perfect our ownership of the gas estate for development and production purposes. We may incur substantial costs to acquire these additional property rights and the acquisition of the necessary rights may not be feasible in some cases. Our inability to obtain these rights may adversely impact our ability to develop these properties. Some states permit us to produce the gas without perfected ownership under an administrative process known as “forced pooling,” which requires 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 forced pooling process is time consuming and may delay our drilling program in the affected areas. In addition, although we believe we have the right to extract and produce coal bed methane from locations where we possess rights to coal, in some cases we may not possess these rights. If we are unable in such cases to obtain those rights from their owners, we will not enjoy the rights to develop coal bed methane with our mining of coal. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves. For example, we have substantial acreage in West Virginia for which we have not reviewed the title to determine what, if any, additional rights would be needed to produce coal bed methane from these locations or the feasibility of obtaining these rights.

Currently the vast majority of our gas producing properties are located in three counties in Virginia, making us vulnerable to risks associated with having our gas production concentrated in one area.

The vast majority of our gas producing properties are geographically concentrated in three counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of gas production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.

Other persons could have ownership rights in our advanced gas extraction techniques which could force us to cease using those techniques or pay royalties.

Although we believe that we hold sufficient rights to all of our advanced gas extraction techniques, other persons could contest our rights and claim ownership of one or more of our advanced techniques for extracting coal bed methane. For example, a third party has asserted that several of our drilling techniques infringed several patents that they hold. A successful challenge to one or more of our advanced extraction techniques could adversely impact our financial performance and results of operation. We might have to pay a royalty which would increase our production costs or cease using that technique which could raise our production costs or decrease our production of coal bed methane. In addition, we could incur substantial costs in defending patent infringement claims, obtaining patent licenses, engaging in interference and opposition proceedings or other challenges to our patent rights or intellectual property rights made by third parties or in bringing such proceedings.

The coal beds and other strata from which we produce methane gas frequently contain water and the gas often contains impurities, both of which may hamper our ability to produce gas in commercial quantities or economically.

Coal beds and other strata frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may affect our profitability. Further, a substantial amount of our gas needs to be processed in order to make it salable to our intended customers. At times, the cost of processing this gas relative to the quantity of gas from a particular well, or group of wells, may outweigh the economic benefit of selling that gas, and our profitability may decrease due to the reduced production and sale of gas.

 

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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, 2007, we had hedges on approximately 24.5 billion cubic feet of our targeted 2008 natural gas production. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.

In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected, the counterparties to our futures contracts fail to perform the contracts, or if our gas hedges would no longer qualify for hedge accounting, we will be required to mark them to market. This may result in more volatility in our income in the future periods.

FORWARD-LOOKING INFORMATION

Various statements in this document, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “would,” “will,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. These risks, uncertainties and contingencies include, but are not limited to, the following:

 

•

an extended decline in prices we receive for our coal and gas affecting our operating results and cash flows;

 

•

reliance on customers extending existing contracts or entering into new long-term contracts for coal;

 

•

reliance on major customers;

 

•

our inability to collect payments from customers if their creditworthiness declines;

 

•

the disruption of rail, barge and other systems that deliver our coal;

 

•

a loss of our competitive position because of the competitive nature of the coal industry and the gas industry, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;

 

•

our inability to hire qualified people to meet replacement or expansion needs;

 

•

coal users switching to other fuels in order to comply with various environmental standards related to coal combustion;

 

•

the inability to produce a sufficient amount of coal to fulfill our customers’ requirements which could result in our customers initiating claims against us;

 

•

increases in the price of commodities used in our mining operations could impact our cost of production;

 

•

foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;

 

•

the risks inherent in coal mining being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, accidents and weather conditions which could cause our results to deteriorate;

 

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•

increases in the price of commodities used in our mining operations could impact our cost of production;

 

•

obtaining governmental permits and approvals for our operations;

 

•

the effects of proposals to regulate greenhouse gas emissions;

 

•

the effects of government regulation;

 

•

the effects of stringent federal and state safety regulations;

 

•

the effects of mine closing, reclamation and certain other liabilities;

 

•

uncertainties in estimating our economically recoverable coal and gas reserves;

 

•

we do not insure against all potential operating risks;

 

•

the outcomes of various legal proceedings, which proceedings are more fully described in our reports filed under the Securities Exchange Act of 1934;

 

•

increased exposure to employee related long-term liabilities;

 

•

our participation in multi-employer pension plans may expose us to obligations beyond the obligation to our employees;

 

•

lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan;

 

•

our ability to comply with laws or regulations requiring that we obtain surety bonds for workers’ compensation and other statutory requirements;

 

•

acquisitions that we recently have made or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made;

 

•

the anti-takeover effects of our rights plan could prevent a change of control;

 

•

risks in exploring for and producing gas;

 

•

new gas development projects and exploration for gas in areas where we have little or no proven gas reserves;

 

•

the disruption of pipeline systems which deliver our gas;

 

•

the availability of field services, equipment and personnel for drilling and producing gas;

 

•

replacing our natural gas reserves which if not replaced will cause our gas reserves and gas production to decline;

 

•

costs associated with perfecting title for gas rights in some of our properties;

 

•

location of a vast majority of our gas producing properties in three counties in southwestern Virginia, making us vulnerable to risks associated with having our gas production concentrated in one area;

 

•

other persons could have ownership rights in our advanced gas extraction techniques which could force us to cease using those techniques or pay royalties;

 

•

the coal beds and other strata from which we produce methane gas frequently contain water and the gas often contains impurities that may hamper production;

 

•

our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;

 

•

other factors discussed above under “Risk Factors” as well as in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007 under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

 

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We caution you that the foregoing list of important factors may not contain all of the material factors that are important to you. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this prospectus may not in fact occur. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. The forward-looking statements in this document speak only as of the date of this document; and we caution you not to rely on them unduly. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events or otherwise, except as otherwise required by law.

 

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USE OF PROCEEDS

Unless otherwise indicated in a prospectus supplement, the net proceeds from the sale of the securities will be used for general corporate purposes, including working capital, acquisitions, retirement of debt and other business opportunities. In the case of a sale by a selling securityholder, we will not receive any of the proceeds from such sale.

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the periods indicated.

 

		Three Months Ended				Twelve Months Ended December 31,
		March 31, 2008				2007				2006				2005				2004			2003
Earnings:
Income from continuing operations before income taxes		$	119,784			$	428,957			$	550,920			$	654,684			$	82,563		$	(33,507	)
Fixed charges, as shown below			17,213				61,336				50,227				42,979				49,349			47,845
Equity in income of investees			(1,355	)			(6,551	)			(1,201	)			(2,850	)			4,317			8,851
Minority Interest – Gas			(9,149	)			(25,038	)			(29,608	)			(9,484	)			—			—
Adjusted Earnings (Loss)		$	126,493			$	458,704			$	570,338			$	685,329			$	136,229		$	23,189	(1)
Fixed charges:
Interest on indebtedness, expensed or capitalized		$	12,834			$	45,414			$	35,818			$	31,903			$	40,180		$	41,212
Interest within rent expense			4,379				15,922				14,409				11,076				9,169			6,633
Total Fixed Charges		$	17,213			$	61,336			$	50,227			$	42,979			$	49,349		$	47,845	(1)
Ratio of Earnings to Fixed Charges			7.35				7.48				11.36				15.95				2.76			—

 

(1)	The deficiency of earnings to cover fixed charges was $24,656 for the year period ended December 31, 2003.

 

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DESCRIPTION OF SECURITIES

This prospectus contains a summary of the securities that CONSOL Energy or certain selling securityholders to be identified in a prospectus supplement may sell. These summaries are not meant to be a complete description of each security. However, this prospectus and any accompanying prospectus supplement contain the material terms of the securities being offered.

DESCRIPTION OF CONSOL ENERGY CAPITAL STOCK

The following summary of the terms of our capital stock is not meant to be complete and is qualified by reference to the relevant provisions of the laws of the state of Delaware and our certificate of incorporation and bylaws. Copies of our certificate of incorporation and bylaws are incorporated herein by reference and will be sent to you at no charge upon request. See “Where You Can Find More Information” below.

General

Our authorized capital stock consists 500,000,000 shares of common stock, par value $0.01 per share, and 15,000,000 shares of preferred stock, par value $0.01 per share, the rights and preferences of which may be established from time to time by our board of directors. As of April 14, 2008, 182,770,137 shares of common stock (excluding shares held in treasury) were outstanding and were held by approximately 113 holders. No shares of preferred stock were issued or outstanding as of April 14, 2008.

Common Stock

Holders of our common stock are entitled to one vote for each share on all matters voted upon by our stockholders, including the election of directors, and do not have cumulative voting rights, which means that the holders of a majority of shares voting for the election of directors can elect all members of our board of directors. Except as otherwise required by applicable law, a majority vote is sufficient for any act of stockholders. Subject to the rights of holders of any then outstanding shares of our preferred stock, our common stockholders are entitled to receive ratably any dividends that may be declared by our board of directors out of funds legally available therefor. Holders of our common stock are entitled to share ratably in our net assets upon our dissolution or liquidation after payment or provision for all liabilities and any preferential liquidation rights of our preferred stock then outstanding. Holders of our common stock do not have preemptive rights to purchase shares of our stock. The shares of our common stock are not subject to any redemption provisions and are not convertible into any other shares of our capital stock. All outstanding shares of our common stock are fully paid and nonassessable. The rights, preferences and privileges of holders of our common stock will be subject to those of the holders of any shares of our preferred stock we may issue in the future.

Our common stock is listed on the New York Stock Exchange under the symbol “CNX.”

The transfer agent and registrar for our common stock is National City Bank.

Preferred Stock

Our board of directors may, from time to time, authorize the issuance of one or more classes or series of preferred stock without stockholder approval.

Our certificate of incorporation permits us to issue up to 15,000,000 shares of preferred stock from time to time. Subject to the provisions of our certificate of incorporation and limitations prescribed by law, our board of directors is authorized to adopt resolutions to issue shares, establish the number of shares, change the number of shares constituting any series, and provide or change the voting powers, designations, preferences and relative

 

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rights, qualifications, limitations or restrictions on shares of our preferred stock, including dividend rights, terms of redemption, conversion rights and liquidation preferences, in each case without any action or vote by our stockholders.

Provisions of Our Certificate of Incorporation and Bylaws

Amendment of the Bylaws. Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our charter and bylaws grant our board the power to adopt, amend and repeal our bylaws on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws at any time by the holders of a majority of the voting power of all outstanding voting stock.

Limitation of Liability of Officers and Directors. Our certificate of incorporation limits the liability of directors to the fullest extent permitted by Delaware law. The effect of these provisions is to eliminate the rights of our company and our stockholders, through stockholders’ derivative suits on behalf of our company, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior. However, exculpation does not apply if the directors breached their duty of loyalty to us and our stockholders, acted in bad faith, knowingly or intentionally violated the law, authorized illegal dividends or redemptions or derived an improper benefit from their actions as directors. In addition, our certificate of incorporation provides that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. We currently have indemnification agreements with our directors and executive officers and also maintain directors and officers insurance.

Advance Notice of Stockholder Proposals. Our bylaws provide that any CONSOL Energy stockholder who is entitled to vote at an annual meeting may propose legally proper business to be voted on by CONSOL Energy stockholders at the annual meeting, but only if the stockholder delivers notice of the proposal in writing to our Secretary. For an annual meeting, the Secretary must receive the notice not less than 90 days nor more than 120 days prior to the first anniversary of the preceding year’s annual meeting. In the event that the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date, notice must be delivered not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to such annual meeting or the 10th day following the day on which the public announcement of the date of such meeting is first made.

For a special meeting, the Secretary must receive the notice not earlier than the close of business on the 120th day prior to such special meeting and not later than the close of business on the later of the 90th day prior to such special meeting or the 10th day following the day on which the public announcement is first made of the date of the special meeting.

Such stockholder’s notice shall set forth:

 

•

for the nomination of directors, all information relating to such nominee that is required to be disclosed under SEC rules to be included in a proxy statement soliciting proxies for the election of the nominee as a director (including such person’s consent to being named as a nominee and to serving as a director if elected);

 

•

for other business, a brief description of the business desired to be brought before the meeting, the text of the proposal or business, the reasons for conducting such business at the meeting and any material interest in such business of such stockholder; and

 

•

as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made (i) the name and address of such stockholder (as in CONSOL Energy’s stock ownership records), and of such beneficial owner, (ii) the class and number of shares which are owned beneficially and of record by such stockholder and a representation that such owners intends to appear

 

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in person or by proxy at the meeting to propose such business or nomination, and (iii) a representation whether the stockholder or beneficial owner, if any, intends or is part of a group which intends to deliver a proxy statement and/or form of proxy to holders of at least the percentage of CONSOL Energy’s outstanding capital stock required to approve or adopt the proposal or elect the nominee and/or otherwise to solicit proxies from stockholders in support of such proposal or nomination.

Nomination of Directors. CONSOL’s bylaws provide that a CONSOL stockholder who was a stockholder of record at the time of giving notice who is entitled to vote at the annual meeting may nominate one or more directors for election, but only if the stockholder delivers timely written notice to our secretary. The timing requirements for receiving the notice are similar as for receiving notice of stockholder proposals described above. The notice must include:

 

•

such information concerning each nominee as would be required under SEC rules to be included in a proxy statement soliciting proxies for the election of the nominee as a director (as well as such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if elected);

 

•

as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the nomination is made (i) the name and address of such stockholder (as in CONSOL’s stock ownership records), and of such beneficial owner, (ii) the class and number of shares which are owned beneficially and of record by such stockholder and a representation that such owner intends to appear in person or by proxy at the meeting to propose such nomination, and (iii) whether the stockholder or beneficial owner intends to deliver a proxy statement and/or form of proxy, and/or otherwise solicit proxies from stockholders.

In addition, if the number of directors to be elected to the board of directors is increased and there is no public announcement naming all of the nominees for director or specifying the size of the increased board of directors at least 100 days prior to the annual meeting, a stockholder’s notice will be deemed to be timely received, but only with respect to the nominees for any new positions created by such increase, if it is delivered not later than the close of business on the 10th day following the date of public disclosure of the meeting date.

For a special meeting, nominations of persons to be elected to the board of directors by or at the direction of the board of directors or a nominating stockholder must be made by notice to our secretary not earlier than the close of business on the 120th day prior to such special meeting and not later than the close of business on the later of the 90th day prior to such special meeting or the 10th day following the date on which public announcement of the special meeting is made.

Special Meetings of Stockholders. Our bylaws provide that subject to the rights of the holders of any series of preferred stock, a special meeting of stockholders may be called only by the Chairman of the Board or by the board of directors pursuant to a resolution adopted by a majority of the entire board.

Possible Anti-Takeover Effects.

Section 203 of Delaware Law

We are a Delaware corporation subject to Section 203 of the Delaware General Corporation Law. Section 203 provides that a corporation generally may not engage in any business combination with any interested stockholder for a period of three years following the time that such stockholder became an interested stockholder. Section 203 applies unless:

 

•

prior to the time a stockholder becomes an interested stockholder, the board of directors of the corporation approved either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder;

 

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•

upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding certain shares); or

 

•

on or after such date the stockholder became an interested stockholder, the business combination is approved by the board of directors of the corporation and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding voting stock which is not owned by the interested stockholder.

An “interested stockholder” is defined to include:

 

•

any person that is the owner of 15% or more of the outstanding voting stock of the corporation or is an affiliate or associate of the corporation and was the owner of 15% or more of the outstanding voting stock of the corporation at any time within the three-year period immediately prior to the relevant date; and

 

•

the affiliates and associates of any such person.

Section 203 defines a business combination to include:

 

•

any merger or consolidation involving the corporation and the interested stockholder;

 

•

any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder;

 

•

certain transactions that result in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder;

 

•

any transaction involving the corporation that increases the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or

 

•

the receipt by the interested stockholder of any loans, advances, guarantees, pledges or other financial benefits provided through the corporation. In general, Section 203 defines an interested stockholder as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by such entity or person.

Under certain circumstances, these provisions could have the effect of delaying, deferring or preventing a change in control of our company during the three-year period or reducing the price that certain investors might be willing to pay in the future for shares of our common stock, although the stockholders may elect to exclude a corporation from the restrictions imposed under Section 203.

Blank Check Preferred Stock

The rights, preferences and privileges of holders of our common stock are subject to, and may be injured by, the rights of the holders of shares of any series of preferred stock that we may designate and issue in the future. The issuance of preferred stock could have the effect of delaying, deferring or preventing a change of control including transactions in which the stockholders might otherwise receive a premium for their shares over the then current market prices.

Stockholder Rights Plan

We have adopted a stockholders’ rights plan under which its stockholders have been granted one preferred stock purchase right for each share of common stock held.

The purchase rights are not exercisable initially. However, upon the earlier of (i) ten business days after we announce that a person has acquired beneficial ownership of 15%, or more of our common stock (the tenth business day after this announcement is referred to as the “flip-in-date”), or (ii) the close of business on such date

 

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as may be fixed by the board of directors, which date shall not be more than 65 days following the commencement of a tender offer or exchange offer that would result in a person or group beneficially owning 15% or more of the outstanding common stock, each purchase right, other than the purchase rights beneficially owned by the acquiring person, will become exercisable and entitle its holder to purchase from us that number of shares of CONSOL Energy’s common stock as shall equal the result obtained by multiplying the purchase price by the then number of preferred share fractions for which a right was exercisable and then dividing that product by 50% of the then current market price per common share. Rights beneficially owned by the acquiring person become void.

In addition, our board of directors may, at its option, at any time after a flip-in-date and before the time the acquiring person becomes the owner of more than 50% of the outstanding shares of CONSOL Energy’s stock, elect to exchange all of the outstanding purchase rights, other than those rights beneficially owned by the acquiring person, for shares of common stock at an exchange ratio prescribed in the rights agreement.

Our board of directors may at any time before a flip-in-date redeem the rights in whole, but not in part, at a price of $0.01 per right.

The purchase rights may cause substantial dilution to a person or group that attempts to acquire a substantial number of shares of CONSOL Energy’s common stock without approval of our board of directors. The rights will not interfere with any merger or other business combination with a third-party approved by our board of directors, because the board may, at any time prior to a flip-in-date, redeem the rights as described above or amend the rights agreement to render it inapplicable to a specific transaction.

DESCRIPTION OF DEBT SECURITIES

The debt securities will be our direct unsecured general obligations. The debt securities will be either senior debt securities or subordinated debt securities. The debt securities that are sold may be exchangeable for and/or convertible into common stock or any of the other securities that may be sold under this prospectus. The debt securities will be issued under one or more separate indentures between us and a bank or trust company that has its principal office in the U.S., as trustee. Senior debt securities will be issued under a senior indenture. Subordinated debt securities will be issued under a subordinated indenture. Each of the senior indenture and the subordinated indenture is referred to as an indenture. The material terms of any indenture will be set forth in the applicable prospectus supplement.

DESCRIPTION OF WARRANTS

We may issue warrants to purchase our debt or equity securities or securities of third parties or other rights, including rights to receive payment in cash or securities based on the value, rate or price of one or more specified commodities, currencies, securities or indices, or any combination of the foregoing. Warrants may be issued independently or together with any other securities and may be attached to, or separate from, such securities. Each series of warrants will be issued under a separate warrant agreement to be entered into between us and a warrant agent. The terms of any warrants to be issued and a description of the material provisions of the applicable warrant agreement will be set forth in the applicable prospectus supplement.

DESCRIPTION OF PURCHASE CONTRACTS

We may issue purchase contracts for the purchase or sale of:

 

•

debt or equity securities issued by us or securities of third parties, a basket of such securities, an index or indices of such securities or any combination of the above as specified in the applicable prospectus supplement;

 

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•

currencies; or

 

•

commodities.

Each purchase contract will entitle the holder thereof to purchase or sell, and obligate us to sell or purchase, on specified dates, such securities, currencies or commodities at a specified purchase price, which may be based on a formula, all as set forth in the applicable prospectus supplement. We may, however, satisfy our obligations, if any, with respect to any purchase contract by delivering the cash value of such purchase contract or the cash value of the property otherwise deliverable or, in the case of purchase contracts on underlying currencies, by delivering the underlying currencies, as set forth in the applicable prospectus supplement. The applicable prospectus supplement will also specify the methods by which the holders may purchase or sell such securities, currencies or commodities and any acceleration, cancellation or termination provisions or other provisions relating to the settlement of a purchase contract.

The purchase contracts may require us to make periodic payments to the holders thereof or vice versa, which payments may be deferred to the extent set forth in the applicable prospectus supplement, and those payments may be unsecured or prefunded on some basis. The purchase contracts may require the holders thereof to secure their obligations in a specified manner to be described in the applicable prospectus supplement. Alternatively, purchase contracts may require holders to satisfy their obligations thereunder when the purchase contracts are issued. Our obligation to settle such pre-paid purchase contracts on the relevant settlement date may constitute indebtedness. Accordingly, pre-paid purchase contracts will be issued under either the senior indenture or the subordinated indenture.

DESCRIPTION OF UNITS

As specified in the applicable prospectus supplement, we may issue units consisting of one or more purchase contracts, warrants, debt securities, shares of preferred stock, shares of common stock or any combination of such securities.

DESCRIPTION OF DEPOSITARY SHARES

As specified in the applicable prospectus supplement, we may issue fractional interests in shares of preferred stock, rather than shares of preferred stock, containing such rights and subject to such terms and conditions as we may specify. If we exercise that option, we will provide for a depositary to issue receipts for depositary shares, each of which will represent a fractional interest in a share of preferred stock. The shares of preferred stock underlying the depositary shares will be deposited under a separate deposit agreement between us and a bank or trust company depositary that has its principal office in the U.S. The prospectus supplement will include the name and address of the depositary.

FORMS OF SECURITIES

Each debt security, warrant, unit or depository share will be represented either by a certificate issued in definitive form to a particular investor or by one or more global securities representing the entire issuance of securities. Certificated securities in definitive form and global securities will be issued in registered form. Definitive securities name you or your nominee as the owner of the security, and in order to transfer or exchange these securities or to receive payments other than interest or other interim payments, you or your nominee must physically deliver the securities to the trustee, registrar, paying agent or other agent, as applicable. Global securities name a depositary or its nominee as the owner of the debt securities, warrants or units represented by these global securities. The depositary maintains a computerized system that will reflect each investor’s

 

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beneficial ownership of the securities through an account maintained by the investor with its broker/dealer, bank, trust company or other representative, as we explain more fully below.

Registered global securities

We may issue the registered debt securities, warrants and units in the form of one or more fully registered global securities that will be deposited with a depositary or its nominee identified in the applicable prospectus supplement and registered in the name of that depositary or nominee. In those cases, one or more registered global securities will be issued in a denomination or aggregate denominations equal to the portion of the aggregate principal or face amount of the securities to be represented by registered global securities. Unless and until it is exchanged in whole for securities in definitive registered form, a registered global security may not be transferred except as a whole by and among the depositary for the registered global security, the nominees of the depositary or any successors of the depositary or those nominees.

If not described below, any specific terms of the depositary arrangement with respect to any securities to be represented by a registered global security will be described in the prospectus supplement relating to those securities. We anticipate that the following provisions will apply to all depositary arrangements.

Ownership of beneficial interests in a registered global security will be limited to persons, called participants, that have accounts with the depositary or persons that may hold interests through participants. Upon the issuance of a registered global security, the depositary will credit, on its book-entry registration and transfer system, the participants’ accounts with the respective principal or face amounts of the securities beneficially owned by the participants. Any dealers, underwriters or agents participating in the distribution of the securities will designate the accounts to be credited. Ownership of beneficial interests in a registered global security will be shown on, and the transfer of ownership interests will be effected only through, records maintained by the depositary, with respect to interests of participants, and on the records of participants, with respect to interests of persons holding through participants. The laws of some states may require that some purchasers of securities take physical delivery of these securities in definitive form. These laws may impair your ability to own, transfer or pledge beneficial interests in registered global securities.

So long as the depositary, or its nominee, is the registered owner of a registered global security, that depositary or its nominee, as the case may be, will be considered the sole owner or holder of the securities represented by the registered global security for all purposes under the applicable indenture, warrant agreement or unit agreement. Except as described below, owners of beneficial interests in a registered global security will not be entitled to have the securities represented by the registered global security registered in their names, will not receive or be entitled to receive physical delivery of the securities in definitive form and will not be considered the owners or holders of the securities under the applicable indenture, warrant agreement or unit agreement. Accordingly, each person owning a beneficial interest in a registered global security must rely on the procedures of the depositary for that registered global security and, if that person is not a participant, on the procedures of the participant through which the person owns its interest, to exercise any rights of a holder under the applicable indenture, warrant agreement or unit agreement. We understand that under existing industry practices, if we request any action of holders or if an owner of a beneficial interest in a registered global security desires to give or take any action that a holder is entitled to give or take under the applicable indenture, warrant agreement or unit agreement, the depositary for the registered global security would authorize the participants holding the relevant beneficial interests to give or take that action, and the participants would authorize beneficial owners owning through them to give or take that action or would otherwise act upon the instructions of beneficial owners holding through them.

Principal, premium, if any, and interest payments on debt securities, and any payments to holders with respect to warrants or units, represented by a registered global security registered in the name of a depositary or its nominee will be made to the depositary or its nominee, as the case may be, as the registered owner of the registered global security. None of CONSOL Energy, the trustees, the warrant agents, the unit agents or any other agent of CONSOL Energy, agent of the trustees or agent of the warrant agents or unit agents will have any

 

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responsibility or liability for any aspect of the records relating to payments made on account of beneficial ownership interests in the registered global security or for maintaining, supervising or reviewing any records relating to those beneficial ownership interests.

We expect that the depositary for any of the securities represented by a registered global security, upon receipt of any payment of principal, premium, interest or other distribution of underlying securities or other property to holders on that registered global security, will immediately credit participants’ accounts in amounts proportionate to their respective beneficial interests in that registered global security as shown on the records of the depositary. We also expect that payments by participants to owners of beneficial interests in a registered global security held through participants will be governed by standing customer instructions and customary practices, as is now the case with the securities held for the accounts of customers in bearer form or registered in “street name,” and will be the responsibility of those participants.

If the depositary for any of these securities represented by a registered global security is at any time unwilling or unable to continue as depositary or ceases to be a clearing agency registered under the Securities Exchange Act of 1934, and a successor depositary registered as a clearing agency under the Securities Exchange Act of 1934 is not appointed by us within 90 days, we will issue securities in definitive form in exchange for the registered global security that had been held by the depositary. Any securities issued in definitive form in exchange for a registered global security will be registered in the name or names that the depositary gives to the relevant trustee, warrant agent, unit agent or other relevant agent of ours or theirs. It is expected that the depositary’s instructions will be based upon directions received by the depositary from participants with respect to ownership of beneficial interests in the registered global security that had been held by the depositary.

PLAN OF DISTRIBUTION

CONSOL Energy and/or the selling securityholders, if applicable, may sell the securities in one or more of the following ways (or in any combination) from time to time:

 

•

through underwriters or dealers;

 

•

directly to a limited number of purchasers or to a single purchaser; or

 

•

through agents.

The prospectus supplement will state the terms of the offering of the securities, including:

 

•

the name or names of any underwriters, dealers or agents;

 

•

the purchase price of such securities and the proceeds to be received by CONSOL Energy, if any;

 

•

any underwriting discounts or agency fees and other items constituting underwriters’ or agents’ compensation;

 

•

any initial public offering price;

 

•

any discounts or concessions allowed or reallowed or paid to dealers; and

 

•

any securities exchanges on which the securities may be listed.

Any initial public offering price and any discounts or concessions allowed or reallowed or paid to dealers may be changed from time to time.

If we and/or the selling securityholders, if applicable, use underwriters in the sale, the securities will be acquired by the underwriters for their own account and may be resold from time to time in one or more transactions, including:

 

•

negotiated transactions;

 

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•

at a fixed public offering price or prices, which may be changed;

 

•

at market prices prevailing at the time of sale;

 

•

at prices related to prevailing market prices; or

 

•

at negotiated prices.

Unless otherwise stated in a prospectus supplement, the obligations of the underwriters to purchase any securities will be conditioned on customary closing conditions and the underwriters will be obligated to purchase all of such series of securities, if any are purchased.

We and/or the selling securityholders, if applicable, may sell the securities through agents from time to time. The prospectus supplement will name any agent involved in the offer or sale of the securities and any commissions we pay to them. Generally, any agent will be acting on a best efforts basis for the period of its appointment.

We and/or the selling securityholders, if applicable, may authorize underwriters, dealers or agents to solicit offers by certain purchasers to purchase the securities from CONSOL Energy at the public offering price set forth in the prospectus supplement pursuant to delayed delivery contracts providing for payment and delivery on a specified date in the future. The contracts will be subject only to those conditions set forth in the prospectus supplement, and the prospectus supplement will set forth any commissions we pay for solicitation of these contracts.

Underwriters and agents may be entitled under agreements entered into with CONSOL Energy and/or the selling securityholders, if applicable, to indemnification by CONSOL Energy and/or the selling securityholders, if applicable, against certain civil liabilities, including liabilities under the Securities Act, or to contribution with respect to payments which the underwriters or agents may be required to make. Underwriters and agents may be customers of, engage in transactions with, or perform services for CONSOL Energy and its affiliates in the ordinary course of business.

Each series of securities other than the common stock, which is listed on the New York Stock Exchange, will be a new issue of securities and will have no established trading market. Any underwriters to whom securities are sold for public offering and sale may make a market in the securities, but such underwriters will not be obligated to do so and may discontinue any market making at any time without notice. The securities, other than the common stock, may or may not be listed on a national securities exchange.

WHERE YOU CAN FIND MORE INFORMATION

CONSOL Energy files annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any reports, statements or other information that CONSOL files at the SEC’s public reference room at 100 F Street, N.E., Washington D.C. 20549. Please call the SEC at 1-800-SEC-0330 for more information on the public reference rooms.

CONSOL Energy’s SEC filings are also available to the public from commercial retrieval services and at the website maintained by the SEC at www.sec.gov, and on CONSOL Energy’s website at www.consolenergy.com. Reports, proxy statements and other information are also available for inspection at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

We filed a registration statement on Form S-3 to register with the SEC the CONSOL Energy securities we may offer and sell pursuant to this prospectus. This prospectus is a part of that registration statement. As allowed by SEC rules, this prospectus does not contain all the information you can find in the registration statement or the

 

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exhibits to the registration statement. You may obtain copies of the Form S-3 (and any amendments to those documents) in the manner described above.

Incorporation of SEC Filings

The SEC allows us to “incorporate by reference” information into this prospectus, which means that we can disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is deemed to be part of this prospectus, except for any information superseded by information contained directly in this prospectus or in a later filed document incorporated by reference in this prospectus. This prospectus incorporates by reference the documents set forth below that CONSOL Energy has previously filed with the SEC. These documents contain important information about CONSOL Energy.

CONSOL’S Annual Report on Form 10-K for the year ended December 31, 2007 filed with the SEC on February 19, 2008;

CONSOL’S 2008 Proxy Statement filed with the SEC on March 27, 2008;

CONSOL’s Form 10-Q for the quarter ended March 31, 2008 filed with the SEC on April 30, 2008; and

CONSOL’S Current Reports on Form 8-K filed on January 29, 2008, February 25, 2008, February 27, 2008, March 25, 2008 and May 1, 2008;

The description of CONSOL Energy’s common stock contained in its registration statement on Form 8-A12B filed with the SEC on March 24, 1999 (file no. 001-14901) together with the description of the associated preferred stock purchase rights included in CONSOL’S registration statement on Form 8-A12G filed with the SEC on December 22, 2003; and

All documents filed by CONSOL Energy pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act with the SEC from the date of this prospectus.

We will provide to each person to whom a copy of this prospectus is delivered, including any beneficial owner, upon the written or oral request of such person, without charge, a copy of any or all of the documents that are incorporated herein by reference. Requests should be directed to: CONSOL Energy Inc. 1800 Washington Road, Pittsburgh, PA 15241-1421, Attention: General Counsel, (412) 831-4000.

 

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EXPERTS

The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting (which is included in Management’s Report on Internal Control over Financial Reporting) of CONSOL incorporated in this Prospectus by reference to CONSOL’s Annual Report on Form 10-K for the year ended December 31, 2007, have been so incorporated in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The information included in this prospectus relating to the proved reserves of gas and oil (including coal bed methane) of CONSOL as of December 31, 2007, 2006, 2005, 2004, and 2003 and as of March 31, 2005, is derived from reserve reports prepared or reviewed by Schlumberger Data and Consulting Services. The information included in this prospectus relating to the proved reserves of gas and oil (including coal bed methane) of CONSOL as of December 31, 2004 and 2003, is derived from reserve reports prepared or reviewed by Ralph E. Davis Associates, Inc. This information is included or incorporated by reference in this prospectus in reliance upon these firms as experts in matters contained in the reports.

 

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38,500,000 Shares

CONSOL Energy Inc.

Common Stock

 

 

PROSPECTUS    SUPPLEMENT

 

BofA Merrill Lynch

PNC Capital Markets LLC

Scotia Capital

Stifel Nicolaus

BMO Capital Markets

Credit Agricole CIB

RBS

UBS Investment Bank

Brean Murray, Carret & Co.

FBR Capital Markets

Howard Weil Incorporated

Pritchard Capital Partners, LLC

 

March 25, 2010