CONSOL Energy Announces 11% Increase in Proved Reserves to 6.3 Tcfe

February 08, 2017

CONSOL Energy Announces 11% Increase in Proved Reserves to 6.3 Tcfe

PITTSBURGH, Feb. 8, 2017 /PRNewswire/ -- CONSOL Energy Inc. (NYSE: CNX) today announced total proved reserves of 6.3 Tcfe, as of December 31, 2016, which is an 11% increase compared to the previous year. Oil, condensate, and liquids account for 423 Bcfe, or 6.8%, of the 6.3 Tcfe total proved reserves, of which the Marcellus and Utica Shale represent 99% of these heavier hydrocarbons.

During 2016, CONSOL Energy added 720 Bcfe of proved reserves through extensions and discoveries, which resulted in CONSOL Energy replacing 183% of its 2016 net production of 394 Bcfe.

In 2016, total capital costs incurred were $165 million. Total capital costs incurred divided by the summation of 720 Bcfe for extensions and discoveries, 1,444 Bcfe for the purchase of reserves in-place, negative 871 Bcfe for the sale of reserves in-place, and negative 290 Bcfe for revisions, yields an all-in finding and development (F&D) cost for proved reserve additions of $0.16 per Mcfe.

In 2016, drilling and completion costs incurred directly attributable to extensions and discoveries were $144 million. When divided by the extensions and discoveries of 720 Bcfe, this yields a drill bit F&D cost of $0.20 per Mcfe, compared to $0.66 per Mcfe at year-end 2015.

Future development costs for proved undeveloped (PUD) reserves are estimated to be approximately $1.191 billion, or $0.46 per Mcfe, compared to $0.48 per Mcfe at year-end 2015.

The following table shows the summary of changes in reserves:

Summary of Changes in Proved Reserves (Bcfe)

Balance at December 31, 2015




Extensions and discoveries                              




Purchase of reserves in-place


Sale of reserves in-place


Balance at December 31, 2016           



Note: The proved reserve estimate for 2016 was prepared by CONSOL Energy and audited by Netherland, Sewell & Associates, Inc.


During the year, total net revisions were negative 290 Bcfe, largely caused by a decrease in pricing. As a result of the Marcellus Shale joint venture (JV) dissolution, CONSOL Energy had a positive net impact on the reserves that were retained: CONSOL Energy effectively sold 871 Bcfe of proved reserves, while purchasing 1,444 Bcfe of proved reserves due to the JV exchange agreement.

Proved developed reserves of 3,683 Bcfe in 2016 comprised 59% of total proved reserves, compared to 66% in 2015. Proved undeveloped reserves (PUDs) were 2,568 Bcfe at December 31, 2016, or 41% of total proved reserves, compared to 34% at year-end 2015. This reflects the company's increased flexibility to accelerate its development plan due to the Marcellus Shale joint venture (JV) dissolution, continued success in the Marcellus Shale, and increased activity in the dry Utica Shale. PUDs at year-end 2016 represent 55% of the total wells the company expects to drill over the next five years.

In the Marcellus Shale, CONSOL Energy and its previous JV partner turned-in-line 47 gross wells with an average completed lateral length of approximately 7,300 feet and expected ultimate recoveries (EUR) averaging approximately 2.3 Bcfe per thousand feet of completed lateral. Enhanced completion techniques have been a significant contributor to Marcellus Shale EUR improvements in 2016, compared to the 2.0 Bcfe per thousand feet of completed lateral booked for the Marcellus Shale during the previous year. These enhanced completion techniques have allowed the company to book approximately 7% of Marcellus PUDs with EURs of 3.6 Bcfe per thousand feet of completed lateral, compared to 3.0 Bcfe per thousand feet booked during the previous year. CONSOL Energy expects to see further improvements in EURs for all of the company's remaining PUD locations due to continuous improvement initiatives regarding completion optimization. As of December 31, 2016, the Marcellus Shale proved reserves were 3,137 Bcfe, which included 1,868 Bcfe of proved developed reserves.

During 2016 in the Utica Shale, CONSOL Energy and its JV partner turned-in-line 15 gross wells with an average completed lateral length of approximately 8,000 feet and EURs ranging up to 2.2 Bcfe per thousand feet of completed lateral. In 2016, the company's type curves that were applied to PUDs remained unchanged compared to the previous year; however, the company expects future upward revisions to type curves through further completion optimization. In 2016, CONSOL booked 1,372 Bcfe of Utica proved reserves, an increase of 6% from the 1,299 Bcfe booked during 2015, which is attributable to the continued drilling success in the Utica Shale. The total Utica proved reserves include 624 Bcfe associated with the dry Utica Shale, or 10% of the company's total reserves.

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

Breakdown of Reserves (Bcfe)












Total Reserve
& Resource

Marcellus Shale









Coalbed Methane





































Definition: Total Reserve & Resource includes total 3P and other resource potential outside of 3P. 

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) Included in the Proved Developed Reserves is 17 Bcfe from two Utica Shale wells in Pennsylvania (PA). The majority of the Utica in PA and West Virginia (WV) fall into the resource classification.


As of December 31, 2016, CONSOL Energy has total proved, probable, and possible reserves (also known as "3P reserves") of 41.4 Tcfe, which is an increase of 3.0 Tcfe, or 8%, in 3P reserves from the 38.3 Tcfe reported at year-end 2015. The increase in 3P reserves is primarily attributed to more certainty of the success in the Ohio Utica Shale, as well as the continued success and optimization in the Marcellus Shale. The company has had strong initial success in the Pennsylvania dry Utica Shale, however it is still early in the play and reserve bookings are currently limited to two proved developed producing (PDP) wells in the 2016 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 Energy'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 table below summarizes both Securities and Exchange Commission (SEC) and strip pricing as of December 31, 2016:



Pricing (1)

Pricing (2)

Variance %

Benchmark Pricing:

WTI Oil Price ($/Bbl)




NYMEX Natural Gas Price ($/MMBtu)




C2+ Natural Gas Liquids ($/Bbl) (3)




Condensate ($/Bbl)





(1) The SEC rules require that the proved reserve calculations be based on the first day of the month average prices over the preceding twelve months. 

(2) Strip pricing as of December 31, 2016 for each of the first five years and flat thereafter.

(3) NGL Pricing is 37% of WTI, which includes regional market differentials.


SEC Pricing: Based on these prices adjusted for energy content, quality, hedges, transportation costs, and basis differentials ($1.73 per Mcf, $15.77 per barrel of natural gas liquids, $24.19 per barrel of condensate and $37.75 per barrel of crude oil, respectively), the pre-tax discounted (10%) present value ("PV-10") of the company's proved reserves was $1.56 billion for 2016, compared to $1.66 billion at year-end 2015. The $1.56 billion includes $440 million associated with hedges.

Strip Pricing: The company's reserve based lending credit facility, which as of December 31, 2016 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, 2016 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 $3.7 billion for 2016.

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, 2016. 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 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

$      11,303

$      11,838

$      28,503

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

$        955

$        1,019

$        2,984


(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 and natural gas liquids 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 natural gas drilling, or our ability to dispose of water used or removed from strata in connection with our natural 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 natural gas and coal operations; the effects of mine closing, reclamation, gas well closing and certain other liabilities; uncertainties in estimating our economically recoverable natural gas, oil and coal reserves; defects may exist in our chain of title and we may incur additional costs associated with perfecting title for natural gas and coal 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; acquisitions and divestitures we anticipate may not occur or produce anticipated benefits; our participation in joint ventures may restrict our operational and corporate flexibility, and actions taken by a joint venture partner may impact our financial position and operational results; risks associated with our debt; replacing our natural gas and oil reserves, which if not replaced, will cause our natural 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 near-term 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 coal sales contracts may provide limited protection during adverse economic conditions, and may result in economic penalties or permit the customer to terminate the contract; a majority of 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; with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC - disruption to our business, including customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results; there is no assurance that the potential dropdowns, spin-off or sale of the coal business will occur, or if it does occur that we will be able to negotiate favorable terms; with respect to the termination of the joint venture with Noble - disruption to our business, including customer and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating and financial results and liquidity; other factors discussed in the 2015 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, resources 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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