PITTSBURGH, Feb. 3, 2015 /PRNewswire/ -- During 2014, CONSOL Energy Inc. (CNX) added 1.1 Tcfe (net to CONSOL) of proved reserves through extensions and discoveries. As of December 31, 2014, total proved reserves were a record 6.8 Tcfe, which represents a 19% increase from the 5.7 Tcfe at year-end 2013. Within the total proved reserves are 510 Bcfe, or 7.5%, of oil, condensate, and liquids. Marcellus Shale reserves account for 454 Bcfe, or 89%, of these heavier hydrocarbons.

CONSOL Energy replaced 466% of its 2014 production, when considering increases from extensions and discoveries of 1.1 Tcfe. Production in 2014 was 236 Bcfe (net to CONSOL).

Much of the increase in extensions and discoveries was due to the company's highly successful Marcellus Shale program. As of December 31, 2014, the Marcellus Shale consisted of 4,235 Bcfe of proved reserves, or a 26% increase from the 3,373 Bcfe when compared to year-end 2013. Marcellus Shale proved developed reserves were 1,367 Bcfe, or an increase of 89% from 725 Bcfe, over the same period.

During 2014, CONSOL Energy turned in line 53 operated Marcellus Shale wells with an average completed lateral length of approximately 7,600 feet and expected ultimate recoveries (EUR) ranging from approximately 1.0 to 3.0 Bcfe per thousand foot completed. The utilization of enhanced recovery techniques of reduced cluster spacing (RCS) and short stage lengths (SSL) resulted in initial 24-hour production rates as high as 20.2 MMcf/d, with 14 wells averaging 10.0 MMcf/d or greater for 30 days. Wells completed utilizing these techniques have shown initial production rates improving by as much as 40%, which translates into increases to well EURs of 15%-20%. In 2014, CONSOL's proved undeveloped reserves reflect the incremental uplift associated with RCS/SSL in the operational area of Southwest Pennsylvania, which represent approximately 10% of total Marcellus proved undeveloped locations and approximately 15% of total Marcellus proved undeveloped reserves. Early RCS/SSL results are positive for other operational areas and indicate likely potential uplift in future reserves.

During 2014, drilling and completion costs incurred directly attributable to extensions and discoveries were $836.7 million. When divided by the extensions and discoveries of 1.1 Tcfe, this yields a drill bit finding and development cost of $0.76 per Mcfe.

The following table shows the summary of changes in reserves.

Note: The proved reserve estimate for 2014 was prepared by CONSOL Energy and audited by Netherland, Sewell & Associates, Inc.

Total net revisions increased reserves by 234 Bcfe, which include performance and price revisions. Performance revisions resulted in a net increase to reserves of 218 Bcfe. As a result of higher gas prices throughout the year, CONSOL continued to focus and develop higher internal rate of return projects in the Marcellus Shale. Price revisions increased reserves by 16 Bcfe. Price adjustments for the 2014 year-end reserves are based on a price of $4.35 MMBtu, which is $0.68 higher than the 2013 year-end price of $3.67 MMBtu. No reserves were added through purchases, as the company did not complete any proved property acquisitions in 2014.

As of December 31, 2014, proved reserves were 53% proved undeveloped (PUDs), as compared to 56% at year-end 2013. This reflects consistent booking of proved undeveloped reserves in 2014, as a result of the company's continued success in the Marcellus Shale. The 2,868 Bcfe of Marcellus Shale PUDs represent only 51% of the total wells the company expects to drill over the next five years.

During 2014, CONSOL Energy turned in line 21 operated Utica Shale wells with an average completed lateral length of approximately 5,700 feet and EURs ranging from approximately 1.0 to 2.0 Bcfe per thousand foot completed. In the Utica Shale, four of the wells peaked at over 10.0 MMcf/d and 1,000 Bbl/d of condensate, averaging over 500 Bbl/d for 30 days. In 2014, CONSOL booked 334 Bcfe of PUDs, which is an increase from the 106 Bcfe booked during 2013.

CONSOL Energy also has total proved, probable, and possible reserves (also known as "3P reserves") of 36.6 Tcfe, as of December 31, 2014. This is an increase of 3.6 Tcfe, or 11%, in 3P reserves from the 33.0 Tcfe reported at year-end 2013. The increase is primarily attributed to continued success and optimization in the Marcellus Shale, as well as an increased certainty in the success of the Utica Shale. The company is testing Upper Devonian and dry Utica potential in Pennsylvania and West Virginia and is optimistic that these areas will add to CONSOL's proved reserves over time. The company's 3P reserves have been determined in accordance with the guidelines of the Society of Petroleum Engineers Petroleum Resources Management System.

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 first day of the month average prices over the preceding twelve months. For the year-end 2014 reserve evaluation, the benchmark prices were $4.35 per MMBtu for natural gas, $46.54 per barrel for natural gas liquids, $75.99 per barrel for condensate and $94.99 per barrel for crude oil (Cushing), representing the simple average of the prices for the first day for each month of 2014. Comparative prices for year-end 2013 were $3.67 per MMBtu for natural gas, $53.03 per barrel for natural gas liquids, $77.52 per barrel for condensate and $96.91 per barrel for crude oil (Cushing). Based on these prices adjusted for energy content, quality, hedges, transportation costs, and basis differentials ($3.85 per Mcf, $46.54 per barrel of natural gas liquids, $75.99 per barrel of condensate and $89.99 per barrel of crude oil, respectively), the pre-tax discounted (10%) present value ("PV10") of the Company's proved reserves was $4.88 billion for 2014 compared to $2.78 billion at year-end 2013.

Standardized Measure of Discounted Future Net Cash Flows

The following information was 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, 2014. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.

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

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

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 economic conditions in any of the industries in which our customers operate or a worldwide financial downturn; an extended decline in prices we receive for our gas, natural gas liquids and coal including the impact on gas prices of our gas operations being concentrated in Appalachia which has experienced a dramatic increase in gas production and decline in gas pricing relative to the benchmark Henry Hub prices; 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 gas and coal to market; a loss of our competitive position because of the competitive nature of the gas and coal industries, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;  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 natural gas and coal, 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; the risks inherent in gas and coal 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 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 and renewing governmental permits and approvals for our gas and coal 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 well or mine; the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current gas and coal operations; the effects of mine closing, reclamation, gas well closing and certain other liabilities; uncertainties in estimating our economically recoverable gas and coal reserves; defects may exist in our chain of title and we may incur additional costs associated with perfecting title for gas or coal 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; 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; replacing our natural gas reserves, which if not replaced, will cause our gas reserves and gas production to decline; acquisitions that we may make in the future involve risks including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and divestitures we may make may not occur or produce anticipated proceeds; existing and future gas joint ventures may restrict our operational and corporate flexibility, we may be materially impacted by actions taken by our joint venture partners and we may not realize anticipated benefits such as carried costs; 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; provisions of our debt agreements may restrict our flexibility and the risks associated with the degree to which we are leveraged; 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; the risks in making strategic determinations, including the allocation of capital and other resources among our strategic opportunities may adversely affect our financial condition; failure by Murray Energy Corporation to satisfy the liabilities it assumed from us as well as to perform its obligations under various agreements; and other factors discussed in the 2013 Form 10-K under "Risk Factors," as updated by our 2014 Form 10-K and 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.

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