Crude Oil ( ) Brent Crude ( ) Natural Gas ( ) S&P 500 ( ) PHLX Oil ( )
 February 5, 2016 - 6:45 AM EST
Print Email Article Font Down Font Up
CONSOL Energy Announces E&P Division Proved Reserves of 5.6 Tcfe; Proved Developed Reserves Increase By 16%; Adds 934 Bcfe from Drilling in 2015; Replaces 284% of 2015 Production

PITTSBURGH, Feb. 5, 2016 /PRNewswire/ -- During 2015, CONSOL Energy Inc. (NYSE: CNX) added 934 Bcfe (net to CONSOL) of proved reserves through extensions and discoveries. As of December 31, 2015, total proved reserves were 5.6 Tcfe, which included 583 Bcfe, or 10.3%, of oil, condensate, and liquids. Marcellus Shale reserves account for 369 Bcfe, or 14.4%, of these heavier hydrocarbons.

CONSOL Energy replaced 284% of its 2015 production, when considering increases from extensions and discoveries of 934 Bcfe. Production in 2015 was 329 Bcfe (net to CONSOL).

During 2015, drilling and completion costs incurred directly attributable to extensions and discoveries were $618.3 million. When divided by the extensions and discoveries of 934 Bcfe, this yields a drill bit finding and development cost of $0.66 per Mcfe, compared to $0.76 per Mcfe at year-end 2014.

Future development costs for PUD reserves are estimated to be approximately $943 million, or $0.48 per Mcfe.

The following table shows the summary of changes in reserves:


Summary of Changes in Proved Reserves (Bcfe)

Balance at December 31, 2014


Price revisions(1) (2)                                           


Plan and other revisions(2)


Extensions and discoveries                               




Balance at December 31, 2015            


Note: The proved reserve estimate for 2015 was prepared by CONSOL Energy and audited by Netherland, Sewell & Associates, Inc.

(1)     Amount of reserves that would not be included in the December 31, 2014 proved reserve balance due to the decrease in natural gas,
natural gas liquids (NGLs), and oil prices in 2015.

(2)     Approximately 2,200 Bcfe within the "Price revisions" and "Plan and other revisions" categories has been removed due to changes to the
company's five year drill plan.

Total net revisions are 1,790 Bcfe, which include negative price revisions of 3,159 Bcfe and net positive plan and other revisions of 1,369 Bcfe. The positive plan and other revisions are primarily driven by performance revisions resulting from CONSOL's success in reducing costs, continued improvements in type curves and EURs in the Marcellus, and focusing on developing higher internal rate of return projects across the company. Approximately 2,200 Bcfe of negative revisions included in price revisions and plan and other revisions have been removed from CONSOL's 5-year development plan.

Proved developed reserves of 3,697 Bcfe in 2015 were 16% higher than 2014 and comprised 66% of total proved reserves, compared to 47% in 2014. Proved undeveloped reserves (PUDs) were 1,946 Bcfe at December 31, 2015, or 34% of total proved reserves, compared to 53% at year-end 2014. This reflects consistent booking of proved undeveloped reserves in 2015, as a result of the company's continued success in the Marcellus Shale and increased activity in the dry Utica. PUDs at year-end 2015 represent 78% of the total wells the company expects to drill over the next five years.

In the Marcellus Shale CONSOL Energy and its joint venture (JV) partner turned in line 81 gross wells with an average completed lateral length of approximately 7,600 feet and expected ultimate recoveries (EUR) averaging approximately 2 Bcfe per thousand feet of completed lateral. Max 24-hour production rates were as high as 19 MMcf per day, with 31 wells peaking at rates greater than 10 MMcf per day and 12 wells peaking at rates greater than 15 MMcf per day. As of December 31, 2015, the Marcellus Shale proved reserves were 2,573 Bcfe, which included 1,689 Bcfe of proved developed reserves.

In the Utica Shale, during 2015 CONSOL Energy and its JV partner turned in line 32 gross wells with an average completed lateral length of approximately 7,600 feet and EURs ranging up to 3 Bcfe per thousand feet of completed lateral. In the Dry Utica Shale, four 100% CONSOL-owned wells peaked at over 20 MMcf per day with the Westmoreland County, PA Gaut 4I testing at a 24-hour flow rate of 61 MMcf per day and the Monroe County, Ohio Switz 6D testing at a 24-hour flow rate in excess of 44 MMcf per day. In 2015, CONSOL booked 876 Bcfe of Utica PUDs, which is an increase of 262% from the 334 Bcfe booked during 2014 and includes 523 Bcfe of offset Dry Utica PUDs in Monroe County, Ohio, due to successful drilling results and cost reductions.

As of December 31, 2015, CONSOL Energy has total proved, probable, and possible reserves (also known as "3P reserves") of 38.3 Tcfe, which is an increase of 1.7 Tcfe, or 5%, in 3P reserves from the 36.6 Tcfe reported at year-end 2014. The increase in 3P reserves is primarily attributed to more certainty in the success of the Ohio Utica Shale, as well as continued success and optimization in the Marcellus Shale. The company has had strong initial success in the Pennsylvania dry Utica Shale, but it is still early in the play and reserve bookings are currently limited to one PDP well in the 2015 reserve report. The company continues testing Upper Devonian and dry Utica potential in Pennsylvania, Ohio, and West Virginia and believes that these areas will provide additional opportunities for 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:

Breakdown of Reserves (Bcfe)


Proved Developed
































Other (1)
















Definition: Total 3P is a summation of total proved, probable, and possible reserves.

The estimates of reserves and future revenue were prepared in accordance with the definitions and guidelines of the SEC
Regulation S-X Rule 4.10(a).

(1) Includes Upper Devonian proved reserves of 55.7 Bcfe and 750 Bcfe of 3P reserves.

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 2015 reserve evaluation, the benchmark prices were $2.59 per MMBtu for natural gas, $15.59 per barrel for natural gas liquids, $26.65 per barrel for condensate and $50.28 per barrel for crude oil (Cushing), representing the simple average of the prices for the first day for each month of 2015. Comparative prices for year-end 2014 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).

Based on these prices adjusted for energy content, quality, hedges, transportation costs, and basis differentials ($2.02 per Mcf, $15.59 per barrel of natural gas liquids, $24.00 per barrel of condensate and $45.28 per barrel of crude oil, respectively), the pre-tax discounted (10%) present value ("PV-10") of the company's proved reserves was $1.66 billion for 2015, compared to $4.88 billion at year-end 2014.

The company's reserve based lending credit facility, which as of December 31, 2015 had a $2 billion borrowing base, is redetermined semiannually in the spring and fall based off the present value of the company's oil and gas reserves at a forward looking price deck. At future strip pricing for natural gas and liquids as of December 31, 2015 adjusted for energy content, quality, hedges, transportation costs, and basis differentials, the pre-tax discounted (10%) PV-10 of the company's proved reserves would be $3.4 billion for 2015.

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, 2015. 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.

Reconciliation of PV-10 to Standardized Measure

December 31,

(Dollars in millions)




Future cash inflows

$      11,838

$      28,503

$      21,603

Future production costs




Future development costs (including abandonments)




Future net cash flows (pre-tax)




10% discount factor




PV-10 (Non-GAAP measure) (1)




Undiscounted income taxes




10% discount factor




Discounted income taxes




Standardized GAAP measure

$        1,019

$        2,984

$       1,681

(1)     We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principle (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.


Cautionary Statements

Various statements in this release, including those that express a belief, expectation or intention, may be considered forward-looking statements under federal securities laws including Section 21E of the Securities Exchange Act of 1934 (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," "will," 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 may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital; prices for natural gas, natural gas and other liquids and coal are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand available for our products, weather and the price and availability of alternative fuels. An extended decline in the prices we receive for our natural gas, natural gas liquids and coal affecting our operating results and cash flows; foreign currency fluctuations could adversely affect the competitiveness of our coal abroad; our customers extending existing contracts or entering into new long-term contracts for coal on favorable terms; our reliance on major customers; our inability to collect payments from customers if their creditworthiness declines or if they fail to honor their contracts; the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our natural gas, natural gas liquids and coal to market; a loss of our competitive position because of the competitive nature of the natural 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 environmental regulations including any relating to greenhouse gas emissions on our operating costs as well as on the market for natural gas and coal and for our securities; the risks inherent in natural gas and coal operations, including our reliance upon third party contractors, 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 and transportation operations; obtaining and renewing governmental permits and approvals for our natural gas and coal 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 natural gas and coal 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 our operations; 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, oil and coal reserves; defects may exist in our chain of title and we may incur additional costs associated with perfecting title for gas rights on some of our properties or failing to acquire these additional rights may result in a reduction of 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; 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; divestitures we anticipate may not occur or produce anticipated benefits; the terms of our existing joint ventures restrict our flexibility, actions taken by the other party in our gas joint ventures may impact our financial position and various circumstances could cause us not to realize the benefits we anticipate receiving from these joint ventures; risks associated with our debt; replacing our gas and oil reserves, which if not replaced, will cause our gas and oil reserves and production to decline; declines in our borrowing base could occur for a variety of reasons, including lower natural gas or oil prices, declines in natural gas and oil proved reserves, and lending regulations requirements or regulations; 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; failure to appropriately allocate capital and other resources among our strategic opportunities may adversely affect our financial condition; failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and cash flows; information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber incident; operating in a single geographic area; certain provisions in our multi-year sales contracts may provide limited protection during adverse economic conditions, and may result in economic penalties or permit the customer to terminate the contract; our common units in CNX Coal Resources LP and CONE Midstream Partners LP are subordinated, and we may not receive distributions from CNX Coal Resources LP or CONE Midstream Partners LP; other factors discussed in the 2014 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.

Logo -

To view the original version on PR Newswire, visit:


Source: PR Newswire (February 5, 2016 - 6:45 AM EST)

News by QuoteMedia