CNX Announces Proved Reserves of 9.63 Tcfe

Rhea-AI Summary

CNX Resources Corporation (NYSE: CNX) reported total proved reserves of 9.63 trillion cubic feet equivalent (Tcfe) as of December 31, 2021. The company successfully added 907 billion cubic feet equivalent (Bcfe) through new discoveries, resulting in a replacement rate of over 153% of 2021's net production of 590 Bcfe. Proved developed reserves increased by 13.5% to 5.9 Tcfe. In 2021, total future development costs for proved reserves were estimated at $1,736 million. The pre-tax discounted present value of these reserves was $8.1 billion, reflecting significant growth from $3.6 billion in 2020.

Positive

• Total proved reserves increased to 9.63 Tcfe, a significant asset base.
• Successfully replaced over 153% of 2021 net production through new discoveries.
• Proved developed reserves rose 13.5% year-over-year.
• Future development costs estimated at $1,736 million indicate robust planning.
• Pre-tax discounted present value of reserves reached $8.1 billion, showing strong valuation growth.

Negative

• None.

PITTSBURGH, Feb. 10, 2022 /PRNewswire/ -- CNX Resources Corporation (NYSE: CNX) ("CNX" or "the company") announced today, total proved reserves of 9.63 Tcfe, as of December 31, 2021. CNX organically added 907 Bcfe of proved reserves through extensions and discoveries, which resulted in the company replacing over 153% of its 2021 net production of 590 Bcfe.

Proved developed reserves increased to 5.9 Tcfe as of December 31, 2021, an increase of 13.5% compared to proved developed reserves of 5.2 Tcfe as of December 31, 2020. Proved developed finding and development costs (PD F&D), which is the net capital required to develop the wells that were turned-in-line in 2021 divided by the net total expected ultimate recoveries (EUR) in Mcfe resulted in an average PD F&D of $0.36 per Mcfe.

"This year's reserve update reflects our strategy to maintain a flat to slightly growing production profile as we remain focused on free cash flow generation and capital allocation," commented Yemi Akinkugbe, Chief Excellence Officer. "Efficiently replacing produced reserves each year, while also growing the proved developed reserve base, is a key component of long-term per share value creation under our current development strategy. As such, PD F&D is a key metric that defines current year capital efficiency in our developed oil and natural gas reserves."

In 2021, future development costs for proved reserves were estimated to be $1,736 million, which includes $1,145 million of drilling and completions capital, $185 million of midstream capital, and $406 million of plugging and abandonment costs. Future development costs for proved undeveloped reserves (PUDs), which includes drilling, completions, and midstream capital, but excludes plugging and abandonment costs, are estimated to be approximately $1,330 million, or $0.36 per Mcfe. PUDs at year-end 2021 represent 60% of the total wells the company expects to drill over the next five years.

The following table shows the summary of changes in reserves:

Summary of Changes in Proved Reserves (Bcfe)
Balance at December 31, 2020	9,550
Extensions and discoveries	907
Performance Revisions and other	316
Price Revisions	87
Plan Changes	(644)
Production	(590)
Balance at December 31, 2021	9,626

Note: The proved reserve estimate as of December 31, 2021, was prepared by CNX Resources and audited by Netherland, Sewell & Associates, Inc.

During the year, total revisions were 403 Bcfe, including 316 Bcfe of positive performance revisions and other changes and 87 Bcfe of positive price revisions. "The 2020 take-in transaction of CNX Midstream Partners (CNXM), structurally lowered CNX's operating costs; therefore, shifts up and down in SEC commodity prices used in the reserve report have less of an impact on our reported reserves than companies with higher operating costs," continued Mr. Akinkugbe. "This structural cost advantage means our economic inventory will not fade in times of low commodity prices.  Additionally, this year's positive performance revisions reflect our continuous operational and engineering efforts to optimize the development of our assets."

During 2021, in the Marcellus and Utica shales, CNX turned-in-line (TIL) 45 gross wells with an average completed lateral length of approximately 12,400 feet and EURs averaging 2.7 Bcfe per thousand feet of completed lateral. The company continues to achieve superior economics and production performance through the use of extended reach laterals in the Marcellus and Utica shales, which have allowed CNX to drive value through maximizing the ultimate recovery of the company's in-place resources.

Proved developed and undeveloped reserves were 5,906 Bcfe (61%) and 3,720 Bcfe (39%), respectively, for 2021. As of December 31, 2021, CNX has total proved, probable, and possible reserves (also known as "3P reserves") of 12.2 Tcfe, which are comprised only of reserves expected to be developed in the company's five-year plan. There are an additional 110 Tcfe of recoverable resources that are economic at current strip pricing in the Other Resource Potential that the company expects to develop beyond the five-year plan. This large inventory of 2P, 3P and Resource assets in addition to our peer leading cost implies meaningful future upside in both the Marcellus and Utica shales in Pennsylvania and West Virginia and will continue to allow the company to add extensions and discoveries over the foreseeable future. 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:

	Proved Developed	Proved Developed Non- Producing	Proved Un- Developed	Total Proved	Probable	Possible	Total 3P	Other Resource Potential	Total Reserve & Resource
Marcellus Shale	4,707	-	2,533	7,240	1,545	577	9,322	35,566	44,888
Coalbed Methane	777	1	310	1,088	-	-	1,088	956	2,044
Utica Shale	415	-	877	1,292	374	110	1,776	37,267	39,043
Other (1)	6	-	-	6	-	-	46	36,216	36,262
Total	5,905	1	3,720	9,626	1,919	687	12,232	110,005	122,237

(1) Other includes Conventional, Upper Devonian and Other Shale formations.

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).

The table below summarizes the Securities and Exchange Commission (SEC) pricing as of December 31, 2021:

	SEC
	Pricing (1)
Benchmark Pricing:
WTI Oil Price ($/Bbl)	$66.56
Average Henry Hub Price ($/MMBtu)	$3.60
C2+ Natural Gas Liquids ($/Bbl)(2)	$32.09
Condensate ($/Bbl) (3)	$55.63

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

(2) NGL Pricing is 48.2% of WTI, which includes regional market differentials.

(3) Condensate Pricing is 83.6% of WTI, which includes regional market differentials.

The average of these prices over the remaining lives of the properties and adjusted for quality, hedges, transportation costs, and basis differentials ($3.19 per Mcf, $28.44 per barrel of natural gas liquids, $55.72 per barrel of condensate and crude oil, respectively). The pre-tax discounted (10%) present value ("PV-10") of the company's proved reserves was $8.1 billion for 2021, compared to $3.6 billion at year-end 2020.

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, 2021. 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 CNX. 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. CNX'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 CNX'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, except gas price/MMBtu)		2021		2020		2019
Average Henry Hub Price ($/MMBtu)		$      3.60		$      1.99		$      2.58
Future cash inflows		$      31,839		$      16,578		$      19,490
Future production costs		(8,247)		(6,072)		(7,903)
Future development costs (including abandonments)		(1,736)		(1,958)		(1,121)
Future net cash flows (pre-tax)		21,856		8,548		10,466
10% discount factor		(13,775)		(4,945)		(6,290)
PV-10 (Non-GAAP measure) (1)		8,081		3,603		4,176
Undiscounted income taxes		(5,839)		(2,235)		(2,721)
10% discount factor		3,640		1,268		1,615
Discounted income taxes		(2,199)		(967)		(1,106)
Standardized GAAP measure		$        5,882		$        2,636		$        3,070

(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.

About CNX Resources

CNX Resources Corporation is one of the largest independent natural gas exploration, development, and production companies, with operations centered in the major shale formations of the Appalachian basin. The company deploys an organic growth strategy focused on responsibly developing its resource base. As of December 31, 2021, CNX had 9.63 trillion cubic feet equivalent of proved natural gas, natural gas liquids, condensate, and oil reserves. The company is a member of the Standard & Poor's Midcap 400 Index. Additional information may be found at www.cnx.com.

Cautionary Statements

We are including the following cautionary statement in this press release to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this press release are forward-looking statements (as defined in 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. These 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 a strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this press release 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: prices for natural gas and natural gas liquids are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand for our products, weather and the price and availability of alternative fuels; unsuccessful drilling efforts or continued natural gas price decreases requiring write downs of our proved natural gas properties, or changes in assumptions impacting management's estimates of future financial results as well as other assumptions such as movement in our stock price, weighted-average cost of capital, terminal growth rates and industry multiples, could cause goodwill and other intangible assets we hold to become impaired and result in material non-cash charges to earnings; a loss of our competitive position because of the competitive nature of the natural gas industry, consolidation within the industry or overcapacity in the industry adversely affecting our ability to sell our products and midstream services; deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions; hedging activities may prevent us from benefiting from price increases and may expose us to other risks; negative public perception regarding our industry could have an adverse effect on our operations; events beyond our control, including a global or domestic health crisis; dependence on gathering, processing and transportation facilities and other midstream facilities owned by others, and disruption of, capacity constraints in, or proximity to pipeline, and any decrease in availability of pipelines or other midstream facilities; uncertainties in estimating our economically recoverable natural gas reserves, and inaccuracies in our estimates; the high-risk nature of drilling, developing and operating natural gas wells; our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their development or drilling; the substantial capital expenditures required for our development and exploration projects, as well as midstream system development; decreases in the availability of, or increases in the price of, required personnel, services, equipment, parts and raw materials in sufficient quantities or at reasonable costs to support our operations; our ability to find adequate water sources for our use in shale gas drilling and production operations, or our ability to dispose of, transport or recycle water used or removed in connection with our gas operations at a reasonable cost and within applicable environmental rules; failure to successfully estimate the rate of decline or existing reserves or to find or acquire economically recoverable natural gas reserves to replace our current natural gas reserves; losses incurred as a result of title defects in the properties in which we invest or the loss of certain leasehold or other rights related to our midstream activities; the impact of climate change legislation, litigation and potential, as well as any adopted, environmental regulations, including those relating to greenhouse gas emissions; environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities; existing and future government laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations; significant costs and liabilities may be incurred as a result of pipeline operations and related increase in the regulation of gas gathering pipelines; changes in federal or state income tax laws; the outcomes of various legal proceedings, including those which are more fully described in our reports filed under the Exchange Act; risks associated with our current long-term debt obligations; a decrease in our borrowing base, which could decrease for a variety of reasons including lower natural gas prices, declines in natural gas proved reserves, asset sales and lending requirements or regulations; Risks associated with our convertible senior notes due May 2026 (the "Convertible Notes"), including the potential impact that the Convertible Notes may have on our reported financial results, potential dilution, our ability to raise funds to repurchase the Convertible Notes, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of the Company; the potential impact of the capped call transaction undertaken in tandem with the Convertible Notes issuance, including counterparty risk; challenges associated with strategic determinations, including the allocation of capital and other resources to strategic opportunities; acquisitions and divestitures, we anticipate may not occur or produce anticipated benefits; there is no guarantee that we will continue to repurchase shares of our common stock under our current or any future share repurchase program at levels undertaken previously or at all; we may operate a portion of our business with one or more joint venture partners or in circumstances where we are not the operator, which may restrict our operational and corporate flexibility and we may not realize the benefits we expect to realize from a joint venture; CONSOL Energy may not be able to satisfy its indemnification obligations in the future and such indemnities may not be sufficient to hold us harmless from the full amount of liabilities for which CONSOL Energy will be allocated responsibility; cyber-incidents could have a material adverse effect on our business, financial condition or results of operations; our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel; terrorist activities could materially adversely affect our business and results of operations.  Additional factors are described in detail under the captions "Forward Looking Statements" and "Risk Factors" in our latest annual report on Form 10-K filed with the Securities and Exchange Commission, as supplemented by our quarterly reports on Form 10-Q.

 

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SOURCE CNX Resources Corporation

FAQ

What are CNX's total proved reserves as of December 31, 2021?

As of December 31, 2021, CNX's total proved reserves are 9.63 trillion cubic feet equivalent (Tcfe).

How much did CNX Resources add to its proved reserves in 2021?

In 2021, CNX Resources added 907 billion cubic feet equivalent (Bcfe) to its proved reserves.

What was the replacement rate of CNX's reserves in 2021?

CNX Resources achieved a replacement rate of over 153% of its net production in 2021.

What are the future development costs for CNX's proved reserves?

The future development costs for CNX's proved reserves are estimated at $1,736 million.

What is the pre-tax discounted present value of CNX's reserves?

The pre-tax discounted present value (PV-10) of CNX's proved reserves is $8.1 billion as of 2021.