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ITEM 1.	CONDENSED FINANCIAL STATEMENTS

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(A)	Included in the Coal segment are sales of $144,155 to First Energy and $138,341 to Xcoal Energy & Resources each comprising over 10% of sales.

(B)	Includes equity in earnings of unconsolidated affiliates of $4,807, $1,944 and $1,184 for Coal, Gas and All Other, respectively.

(C)	Includes investments in unconsolidated equity affiliates of $39,373, $108,858 and $51,990 for Coal, Gas and All Other, respectively.

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(D)	Includes equity in earnings of unconsolidated affiliates of $4,462, $484 and $535 for Coal, Gas and All Other, respectively.

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ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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CONSOL Energy announced certain changes to the salaried other post-retirement benefit plan that current retirees and current active employees will receive as of January 1, 2014. The change provides a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The money in the account can be used to help pay for a commercial medical plan, Medicare Part B and Part D premiums and other qualified expenses. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug coverage. Employees who work or worked in corporate or operations support positions who are under age 50 at December 31, 2013 will receive no retiree medical or prescription drug benefit. CONSOL Energy remeasured the salaried other postretirement plan as of March 31, 2012 to recognize these changes. The remeasurement reflects the change in benefit and the change in discount rate from 4.51% at December 31, 2011 to 4.57% at March 31, 2012. The remeasurement resulted in a reduction of approximately $80.6 million of Other Post-Retirement Benefits (OPEB) liability with a corresponding offset to Other Comprehensive Income, net of applicable deferred taxes. The change did not result in any reductions to OPEB expense in the three months ended March 31, 2012. OPEB expense is expected to be $9,425 lower than the $148,419 that was expected to be recognized over the remaining nine months of 2012. The change was made to align CONSOL Energy's corporate and operational support compensation package more closely with our peer group.

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Pennsylvania enacted Act 13 of 2012, which provides for the comprehensive regulation of Marcellus Shale development in Pennsylvania. Among other things, Act 13 requires an impact fee be paid annually on all nonconventional gas wells drilled in the state. The annual fee is based on annual average sales price and is modified annually for a 15-year period for each well. The impact fee also required the first year fee be paid on all applicable wells drilled before January 1, 2012 with subsequent annual fees to apply each year thereafter. CONSOL Energy's retroactive impact fee related to wells drilled prior to January 1, 2012 was approximately $4 million.

•	West Virginia has an alternative bond system (ABS) for coal mine reclamation which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a bond pool (Special

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•	In April 2012, CONSOL Energy entered into an agreement for the sale of its non-core Elk Creek reserves in southern West Virginia. The transaction will be reflected in April 2012 and will result in cash proceeds of approximately $25 million and a gain on sale of assets of approximately $10 million.

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Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel, synthetic rubber and steel that we use in our operations, (ii) increased scrutiny of existing safety regulations and the development of new safety regulations and (iii) additional environmental restrictions such as air emission regulations.

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Federal and state environmental regulators are reviewing our operations more closely and are more strictly interpreting and enforcing existing environmental laws and regulations, resulting in increased costs and delays. For example, we entered into a consent decree with the EPA and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of total dissolved solids in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million. The new facility must be placed into service no later than May 2013.

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Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business.   These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules.  All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal. Another example is the Cross-State Air Pollution Rule (CSAPR) that was finalized by the EPA on July 6, 2011, although the effective date of the rule has been stayed by a court.  CSAPR replaces the Clean Air Interstate Rule and regulates the amount of SO2 and NOx that power plants in 23 eastern states can emit in order to meet clean air requirements in downwind states.  Another example is the Mercury and Air Toxic Standards issued by the EPA on December 16, 2011.  The new regulations set mercury and air toxic standards for new and existing coal and oil fired electric utility steam generating units and include more stringent new source performance standards (NSPS) for particulate matter (PM), SO2 and NOx.  Some older coal fired power plants may be retired or have operation time reduced rather than install additional expensive emission controls which could reduce the amount of coal consumed.  In April 2012, the EPA published its proposed new source emission standards for carbon dioxide for electric power plants.  The rule would apply to new power plants and to existing plants that make major modifications.  There is a 60 day comment period.  If the rule is adopted as proposed, the only new power plants that can meet the proposed emission limits would be coal fired plants with carbon dioxide capture and control and gas fired plants. On April 18, 2012, the EPA published new final rules for gas wells and related facilities.  These New Source Performance Standards apply to wells that were hydraulically fractured after August, 23, 2011 and require the implementation by January 1, 2015 of technologies that capture the gas that is currently vented or flared during completion (hydrofracturing) of a well.  Low pressure wells, including coalbed methane wells, are excluded from these new standards.

•	CONSOL Energy continues to explore potential sales of non-core assets.

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•	Employee wages and related expenses increased $1 million in the period-to-period comparison due to annual wage increases and increased employee benefit costs.

•	Consulting and professional services remained consistent in the period-to-period comparison.

•	Miscellaneous general and administrative expenses increased slightly in the period-to-period comparison due to various transactions, none of which were individually material.

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•	Average operating costs per thermal ton sold increased due to fewer tons sold. Fixed costs are allocated over less tons, resulting in higher unit costs.

•	Average operating costs per thermal ton sold also increased due to the idling of the Blacksville Mine longwall during the first quarter of 2012. The decrease in tonnage negatively impacted the average operating costs per thermal ton sold by approximately $0.58 per ton.

•	Labor and related benefits average costs per ton sold increased. This was due to additional employees and the impact of the wage increases of $2.00 per hour worked related to the new collective bargaining agreement in the period-to-period comparison.

•	Average operating supplies & maintenance cost per ton sold increased due to higher fuel costs, increased pumpable crib installations, increased equipment maintenance costs and the timing of major equipment overhaul costs in the period-to-period comparison.

•	Production taxes average cost per ton sold increased due to the $4.18 per ton higher average sales price.

•	Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs have also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.

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Average operating costs per unit increased due to the mix of mines shipping high volatile metallurgical coal. The increased cost structure of high volatile metallurgical coal is due to more Central Appalachian mines shipping high vol tons. Central Appalachian mines shipping high volatile metallurgical tons have higher cost structures than the Northern Appalachian mines included in the prior period.

•	Labor and related benefits increased due to higher employee counts and additional hours worked in the period-to- period comparison.

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Average operating supplies & maintenance costs per ton sold increased due to additional maintenance, equipment overhaul costs and increased fuel and blasting costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced and major equipment overhauls in the current period. Additional fuel and blasting costs were due to increased surface tonnage moved in the period-to-period comparison.

•	In-transit charges average cost per ton sold increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the Central Appalachian mines which shipped high volatile metallurgical coal in the current period.

•	Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.

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•	Average operating costs per low volatile ton sold primarily increased due to fewer tons sold. Fixed costs are allocated over less tons, resulting in higher unit costs.

•	Average operating costs per low volatile ton sold also increased due to the idling of the Buchanan Mine longwall in March 2012. The decrease in tonnage negatively impacted the average operating costs per low volatile ton sold by approximately $16.46 per ton.

•	Average labor and related benefits increased in the period-to-period comparison due to additional employees and increased wages.

•	Average operating supplies and maintenance costs were impaired due to the decreased sales tonnage; however, total operating supplies and maintenance costs were improved due to the idling of longwall operations during the current period.

•	Average gas well plugging and degasification costs were improved do to fewer degasification wells drilled in the current period.

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Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset in freight revenue. Freight expense increased $12 million primarily due to increased shipments on contracts for which CONSOL Energy contractually provides transportation services.

•	Purchased coal costs decreased approximately $1 million in the period-to-period comparison primarily due to various transactions that occurred throughout both periods, none of which were individually material.

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Closed and idle mine costs decreased approximately $5 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. Closed and idle mine costs decreased $3 million as the result of a decision to permanently abandon Mine 84. Closed and idle mine costs decreased $2 million due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.

•	Other expenses related to the coal segment decreased $3 million in the period-to-period comparison due to various miscellaneous transactions, none of which were individually material.

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•	Other costs were $2 million higher in the period-to-period comparison primarily due to environmental clean-up costs incurred during the three months ended March 31, 2012 at several well sites.

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•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2012 period.

•	Stock-based compensation was higher in the period-to-period comparison due to an increased allocation from CONSOL Energy as a result of an increase in total CONSOL Energy stock-based compensation expense.  The increase in CONSOL Energy stock-based compensation expense is due to additional awards granted in the period-to-period comparison.

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PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The $4 million represents this one-time initial assessment on wells drilled prior to January 1, 2012. On-going PA impact fees which relate to current year wells drilled are included as part of lifting costs in the Marcellus gas segment.

•	Unutilized firm transportation represents excess pipeline transportation capacity that the gas division obtained to enable gas production to flow on an uninterrupted basis as the gas operations continue to increase sales volumes.

•	Bank Fees remained consistent in the period-to-period comparison.

•	Other expenses increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

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Interest expense primarily decreased $4 million due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period. Interest expense also decreased $2 million in the period-to-period comparison primarily due to the 2011 redemption of the 7.875% notes that were due in 2012, being replaced by the 2011 issuance of the 6.375% senior unsecured notes due March 2021. Additionally, a $1 million decrease in interest expense is due to lower borrowings on the revolving credit facilities.

•	Bank fees decreased $2 million due to lower borrowings on the CNX Gas revolving credit facility in the period-to-period comparison.

•	Evaluation fees for non-core asset dispositions remained consistent in the period-to-period comparison.

•	Other corporate items increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Operating cash flow decreased $95 million in 2012 due to lower net income in the period-to-period comparison.

•	Operating cash flows decreased due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years, none of which were individually material.

•	During the 2012 period, $14 million was contributed to CONE Gathering LLC (CONE) in order to meet the operating and capital expenditure needs of the joint venture. The joint venture, of which CONSOL Energy owns 50%, was established on September 30, 2011 to develop and operate the gas gathering system in the Marcellus Shale play.

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Total capital expenditures increased $52 million to $306 million in the three months ended March 31, 2012 compared to $254 million in the three months ended March 31, 2011. Capital expenditures for the gas segment decreased $55 million primarily due to a decrease in Marcellus Shale drilling in the period-to-period comparison. Capital expenditures for coal and other activities increased $107 million in the period-to-period comparison. The ongoing development and expenditures of the BMX mine, which is scheduled to go on-line in 2014, increased $30 million in the period-to-period comparison. Capital expenditures for the Northern West Virginia RO system were $18 million for the 2012 period. The remaining increase was due to various projects throughout both periods, none of which were individually material.

•	Proceeds from the sale of assets increased $28 million in the period-to-period comparison primarily due to the sale of several non-core assets including previously mined surface properties and rights-of-way.

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•	In 2011, proceeds of $250 million were received in connection with the issuance of $250 million of 6.375% senior unsecured notes due in March 2021.

•	In 2011, CONSOL Energy repaid $200 million of borrowings under the accounts receivable securitization facility.

•	In 2011, CONSOL Energy paid outstanding borrowings of $113 million under the revolving credit facilities. CONSOL Energy had no amounts outstanding on the revolving credit facilities for the three months ended March 31, 2012.

•	Dividends of $28 million were paid in 2012 compared to $23 million in 2011. This is due to the increase of the quarterly dividend by 25%, or $0.10 per share, to $0.125 per share in the 2012 period.

(a)	Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2012 contributions are expected to approximate $110 million.

(b)	Other long-term liabilities include mine reclamation and closure and other long-term liability costs.

(c)	The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

•	An aggregate principal amount of $1.5 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.

•	An aggregate principal amount of $1.25 billion of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.

•	An aggregate principal amount of $250 million of 6.375% notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.

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•	An aggregate principal amount of $103 million of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 5.75% per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year.

•	$31 million in advance royalty commitments with an average interest rate of 6.73% per annum.

•	An aggregate principal amount of $64 million of capital leases with a weighted average interest rate of 6.32% per annum.

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•	deterioration in global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;

•	a significant or extended decline in prices we receive for our coal and natural gas affecting our operating results and cash flows;

•	our customers extending existing contracts or entering into new long-term contracts for coal;

•	our reliance on major customers;

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

•	the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our coal and natural gas to market;

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

•	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 emissions;

•	the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for coal and natural gas

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

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

•	decreases in the availability of, or increases in, the price of commodities or capital equipment used in our mining operations;

•	decreases in the availability of, an increase in the prices charged by third party contractors or, failure of third party contractors to provide quality services to us in a timely manner could impact our profitability;

•	obtaining and renewing governmental permits and approvals for our coal and gas operations;

•	the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our coal and natural gas operations;

•	our ability to find adequate water sources for our use in gas drilling, or our ability to dispose of water used or removed from strata in connection with our gas operations at a reasonable cost and within applicable environmental rules;

•	the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a mine or natural gas well;

•	the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current coal and gas operations;

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

•	uncertainties in estimating our economically recoverable coal and gas reserves;

•	costs associated with perfecting title for coal or gas rights on some of our properties;

•	the impacts of various asbestos litigation claims;

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

•	increased exposure to employee-related long-term liabilities;

•	our accruals for obligations for long-term employee benefits are based upon assumptions which, if inaccurate, could result in our being required to expend greater amounts than anticipated;

•	due to our participation in an underfunded multi-employer pension plan, we have exposure under that plan that extends beyond what our obligation would be with respect to our employees and in the future we may have to make additional cash contributions to fund the pension plan or incur withdrawal liability;

•	lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan exceeding total service and interest cost in a plan year;

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acquisitions and joint ventures that we recently have completed or entered into 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 and divestitures we anticipate may not occur or produce anticipated proceeds including joint venture partners paying anticipated carry obligations;

•	the terms of our existing joint ventures restrict our flexibility and actions taken by the other party in our gas joint ventures may impact our financial position;

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

•	risks associated with our debt;

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

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

•	other factors discussed in our 2011 Form 10-K 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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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 4.	CONTROLS AND PROCEDURES

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ITEM 1.	LEGAL PROCEEDINGS

ITEM 6.	EXHIBITS

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