PITTSBURGH, Feb. 6, 2012 /PRNewswire/ -- During 2011, CONSOL Energy Inc. (NYSE: CNX) announced net proved reserve adds through extensions and discoveries of 517 Bcf. The company's estimate of 2011 drilling and completion costs incurred and directly attributable to extensions and discoveries was $237.4 million. This number, when divided by the extensions and discoveries of 517 Bcf, yields a drill bit finding and development cost of $0.47 per mcf. CONSOL Energy attributes this excellent result to superb geology, continued refinement of drilling and completion technology, and its held-by-production (HBP) acreage in the Marcellus Shale. The HBP acreage enables the company to achieve economies of scale by drilling multiple wells from the same pad. During 2011, CONSOL Energy believes it achieved an industry first in the Marcellus Shale, by drilling 10 wells from its Hutchinson pad, in northwestern Westmoreland County, Pa.
CONSOL Energy also replaced 528% of gas production, when considering all increases from extensions and discoveries (517 Bcf), as well as performance (306 Bcf) and price (-10 Bcf) revisions. Production in 2011 was 154 Bcf (net to CONSOL).
Total proved reserves, as of December 31, 2011, were 3.480 Tcf. This represents a 7% decrease versus the 3.732 Tcf at year-end 2010. However, 2011 proved reserves would have been 911 Bcf higher than the 3,732 Bcf, had it not been for 531 Bcf related to the divestitures of the Antero overriding royalty interest and the joint venture with Noble Energy, and the elimination of 380 Bcf proved undeveloped reserves (PUDs) no longer expected to be developed within the next five years. The company is redirecting its drilling capital away from conventional and coalbed methane (CBM) formations and towards the Marcellus and Utica shales. In the future, if CONSOL decides to drill the conventional and CBM formations at a faster pace, these PUDs could return to the proved reserves.
Performance revisions to proved developed producing (PDPs) increased reserves by 306 Bcf, as wells drilled before 2011 produced above earlier expectations. No reserves were added through purchases, as the company did not complete any proved property acquisitions in 2011. Price revisions decreased proved reserves by 10 Bcf.
The proved reserve estimate for 2011 was prepared by CONSOL Energy and audited by Netherland, Sewell & Associates, Inc. The following table shows the summary of changes in reserves. Over 99 percent of the company's proved reserves are gas.
Summary of Changes in Proved Reserves (Bcf)
Balance at December 31, 2010
Extensions and discoveries
Development plan changes
Balance at December 31, 2011
On January 17, 2012, CONSOL reported 78 horizontal wells were drilled and 57 wells were turned online in the Marcellus Shale last year. Total well costs averaged $5.0 million. The expected ultimate recovery (EUR) averaged 5.2 Bcf per well. The average drilled lateral was 3,850 feet, with an average treated portion of 3,367 feet. Maximum 24-hour production averaged 5.0 MMcf per well per day, while 30-day production averaged 3.5 MMcf per well per day. Total daily production from the Marcellus Shale grew from 40 MMcf per day as of December 31, 2010 to 77.5 MMcf per day (net to CONSOL) as of December 31, 2011.
The reserves from our 2011 Marcellus Shale program averaged 5.2 Bcf per well. When one considers that CONSOL's treated laterals averaged 3,367 feet, this means that the company booked about 1.55 Bcf of reserves for every 1,000 feet of lateral.
Year-end 2011 proved reserves were only 39% proved undeveloped, as compared to 48% at year-end 2010.
The company also has total proved, probable, and possible reserves (also known as "3P reserves") of 20.2 Tcf as of December 31, 2011. This is an increase of 5.9 Tcf, or 41%, in 3P reserves from the 14.3 Tcf reported at year-end 2010. This increase is even more impressive when one considers that the company sold one-half of its Marcellus position during 2011. There could be further upside, too, because the 3P reserves are not assuming any contribution from the Utica Shale. 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 Bcf, from the company's current development and exploration plays:
Breakdown of Reserves (Bcf)
Definition: Total 3P is a summation of total proved, probable, and possible reserves.
*Note: "Other Shales" excludes any Utica Shale.
The estimates of reserves and future revenue have been prepared in accordance with the definitions and guidelines of the SEC Regulation S-X Rule 4.10(a).
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 2011 reserve evaluation, the benchmark prices were $4.12 per Mmbtu for natural gas and $95.61 per barrel for crude oil (Cushing), representing the simple average of the prices for the first day for each month of 2011. Comparative prices for year-end 2010 were $4.38 per Mmbtu for natural gas and $79.81 per barrel for crude oil (Cushing). Based on these prices adjusted for energy content, quality and basis differentials ($3.55 per Mmbtu, $49.17 per barrel of natural gas liquids and $85.59 per barrel of crude oil, respectively), the pre-tax discounted (10%) present value ("PV10") of the Company's proved reserves was $2.9 billion for 2011 compared to $2.8 billion at year-end 2010.
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 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; 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 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; 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 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; costs associated with perfecting title for coal or gas rights on some of our properties; 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; and other factors discussed in the 2010 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.
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