CONSOL Energy Adds 954 Bcfe from Drilling in 2012; Achieves Drill Bit Finding Cost of $0.46 per Mcfe; Replaces 611% of 2012 Gas Production; Proved Gas Reserves Grow 15% to Record 4.0 Tcfe

PITTSBURGH, Feb. 7, 2013 /PRNewswire/ -- During 2012, CONSOL Energy Inc. CNX announced that it added 954 Bcfe (net to CONSOL) of proved reserves through extensions and discoveries. The company's estimate of drilling and completion costs incurred during 2012 directly attributable to extensions and discoveries was $440.7 million. When divided by the extensions and discoveries of 954 Bcfe, this yields a drill bit finding and development cost of $0.46 per mcfe. This is the third consecutive year that CONSOL Energy has achieved sub-$0.50 per mcfe drill bit finding and development costs. The company believes this is among the lowest in the industry.

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Total proved reserves, as of December 31, 2012, were a record 3.993 Tcfe, which represents a 15% increase from the 3.480 Tcfe at year-end 2011. Within the total proved reserves are approximately 88 Bcfe, or 2.2%, of oil, condensate, and liquids. Marcellus Shale reserves account for approximately 83 Bcfe, or 94%, of these heavier hydrocarbons.

CONSOL Energy replaced 611% of its 2012 gas production, when considering increases from extensions and discoveries of 954 Bcfe. Production in 2012 was 156 Bcfe (net to CONSOL).

Much of the increase in reserves through the category extensions and discoveries was due to the company's highly successful Marcellus Shale program. As of December 31, 2012, the Marcellus Shale consisted of 1,805 Bcfe of proved reserves. This was a 105% increase from the 882 Bcfe shown at year-end 2011. Marcellus Shale proved developed reserves were 427 Bcfe, or an increase of 79% from 239 Bcfe, over the same period.

As reported on January 18, 64 CONSOL-operated horizontal wells were drilled in the Marcellus Shale in 2012 and 51 were turned on line. Total well costs averaged $6.7 million. The expected ultimate recovery (EUR) averaged 5.9 Bcfe per well. The average drilled lateral length was 5,514 feet. Maximum 24-hour production averaged 8.1 MMcf per well per day, while 30-day production averaged 4.7 MMcf per well per day. Total daily production from the Marcellus Shale grew from 77.5 MMcf per day as of December 31, 2011 to 135.0 MMcf per day (net to CONSOL) as of December 31, 2012.

The following table shows the summary of changes in reserves.

Note: The proved reserve estimate for 2012 was prepared by CONSOL Energy and audited by Netherland, Sewell & Associates, Inc.

Total net revisions decreased reserves by 285 Bcfe, which include performance revisions, plan changes, and reserves lost due to price. Performance revisions increased reserves by 242 Bcfe. Plan changes resulted in lowering our 5-year drilling forecast and removing wells in non-core areas. Lower gas prices resulted in the company shifting towards higher internal rate of return projects, which led to a continued focus in the Marcellus. Price revisions and plan changes decreased reserves by 527 Bcfe. Price adjustments for 2012 year-end are based on a price of $2.76 MMBtu, which is $1.36 lower than the 2011 year-end price of $4.12 MMBtu. No reserves were added through purchases, as the company did not complete any proved property acquisitions in 2012.

As of December 31, 2012, proved reserves were 46% proved undeveloped (PUDs), as compared to 39% at year-end 2011. This was a result of reserves previously classified as proved developed reserves (PDPs) being removed this year due to lower prices. It also reflects the booking of additional proved undeveloped reserves in 2012, as a result of the Marcellus Shale success previously mentioned. The 1,379 Bcfe of Marcellus Shale PUDs, though, represent only 38% of the total expected to be drilled in the coming five years.

As previously reported, initial Utica Shale drilling results have been very encouraging in Noble County, Ohio. Reserve bookings from the Utica Shale, however, have been minimal, so far, because the two drilled Noble County wells are not yet producing.

The company also has total proved, probable, and possible reserves (also known as "3P reserves") of 22.2 Tcfe as of December 31, 2012. This is an increase of 2.0 Tcfe, or 10%, in 3P reserves from the 20.2 Tcfe reported at year-end 2011. The company's 3P reserves have been determined in accordance with the guidelines of the Society of Petroleum Engineers Petroleum Resources Management System (SPE-PRMS).

The following table shows the breakdown of reserves, in Bcfe, from the company's current development and exploration plays:

The Securities and Exchange Commission ("SEC") rules require that the proved reserve calculations be based on the prompt month average prices over the preceding twelve months. For the year-end 2012 reserve evaluation, the benchmark prices were $2.76 per MMBtu for natural gas, $52.09 per barrel for natural gas liquids, $75.77 per barrel for condensate and $94.71 per barrel for crude oil (Cushing), representing the simple average of the prices for the first day for each month of 2012. Comparative prices for year-end 2011 were $4.12 per MMBtu for natural gas, $52.90 per barrel for natural gas liquids, $76.95 per barrel for condensate and $95.61 per barrel for crude oil (Cushing). Based on these prices adjusted for energy content, quality, hedges and basis differentials ($2.81 per Mcf, $52.09 per barrel of natural gas liquids, $75.77 per barrel of condensate and $89.71 per barrel of crude oil, respectively), the pre-tax discounted (10%) present value ("PV10") of the Company's proved reserves was $1.24 billion for 2012 compared to $2.86 billion at year-end 2011.

Cautionary Statements

Various statements in this release, including those that express a belief, expectation or intention, may be considered forward-looking statements (as defined in Section 21E of the Exchange Act) 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 press release, if any, speak only as of the date of this press release; we disclaim any obligation to update these statements. 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: 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; an extended decline in demand for or in the prices we receive for our coal and gas affecting our operating results and cash flows; our customers extending existing contracts or entering into new long-term contracts for coal; the expiration or failure to extend existing long-term contracts; 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 gas to market; 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 failure 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, as well as the impact of any adopted regulations on our coal mining operations due to the venting of coalbed methane which occurs during mining; foreign currency fluctuations could adversely affect the competitiveness of our coal abroad; the risks inherent in coal and 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; our focus on new gas development projects and exploration for gas in areas where we have little or no proven gas reserves; decreases in the availability of, or increases in, the price of commodities and services used in our mining and gas operations, as well as our exposure under "take or pay" contracts we entered into with well service providers to obtain services of which if not used could impact our cost of production; obtaining, maintaining 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 gas operations; the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a mine or well; the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current coal and gas operations; the effects of mine closing, reclamation, gas well closing and certain other liabilities; uncertainties in estimating our economically recoverable coal and gas reserves; defects may exist in our chain of title and we may incur additional costs associated with perfecting title for coal or gas rights on some of our properties or failing to acquire these additional rights we may have to reduce our estimated reserves; the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934; the impacts of various asbestos litigation claims; increased exposure to employee related long-term liabilities; increased exposure to multi-employer pension plan 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 exceeding total service and interest cost in a plan year; 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 anti-takeover effects of our rights plan could prevent a change of control; increased exposure on our financial performance due to the degree we are leveraged; replacing our natural gas reserves, which if not replaced, will cause our gas reserves and gas production to decline; our ability to acquire water supplies needed for 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; our hedging activities may prevent us from benefiting from price increases and may expose us to other risks; changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our financial position and profitability to deteriorate; and other factors discussed in the 2012 Form 10-K under "Risk Factors," as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations.  We may use certain terms in this press release, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC.  These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain.  We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

SOURCE CONSOL Energy Inc.