CNX Announces 2023 Year End Reserves

PITTSBURGH, Feb. 8, 2024 /PRNewswire/ -- CNX Resources Corporation (NYSE: CNX) ("CNX" or "the company") announced today its year-end reserves update as of December 31, 2023.

The Company reported 2023 total proved reserves of 8,741 Bcfe, comprised of 6,028 Bcfe of proved developed reserves and 2,713 Bcfe of proved undeveloped reserves.
Development activity in 2023 converted 819 Bcfe of proved undeveloped reserves, achieving a 1.46x proved developed replacement ratio.
Future finding and development costs for proved undeveloped reserves of $0.43 per Mcfe and $0.50 per Mcfe when including midstream and water infrastructure investments.
Average EUR of proved undeveloped reserves in Marcellus and Utica shales of 2.57 Bcfe and 2.73 Bcfe per thousand feet of completed lateral, respectively.
Upward proved reserves adjustments of 467 Bcfe due to positive well performance and other changes, primarily offset by downward adjustments of 709 Bcfe due to the SEC five-year booking rule and 465 Bcfe due to lower commodity prices.

"The 2023 year-end reserve update highlights the company's continued replacement of production with capital-efficient development of highly productive reserves against a challenging commodity pricing backdrop," commented Navneet Behl, Chief Operating Officer. "Well and cost performance remain strong, and we continue to refine well timing and placement to optimize reserve development and free cash flow generation as we execute our maintenance of production plan. In addition to the reported proved reserves, CNX has an extensive inventory of high-quality acreage and locations that provides decades of runway for long term intrinsic per share value creation at our current development pace."

Proved Developed Reserves

Summary of Changes in Proved Developed Reserves (Bcfe)
Balance at December 31, 2022	6,221
Production	(560)
Sale of Reserves	(168)
Price Revisions	(283)
Transferred from Undeveloped	819
Extensions and Discoveries	42
Other Revisions	(43)
Balance at December 31, 2023	6,028

Proved developed reserves reported at 6,028 Bcfe, or a decrease of 193 Bcfe, compared to 2022. This decrease was driven by production, asset sales during the year, and commodity price adjustments affecting the long-term tail production economics; offset in part, by the conversion of undeveloped reserves.

Proved Undeveloped

Summary of Changes in Proved Undeveloped Reserves (Bcfe)
Balance at December 31, 2022	3,585
Undeveloped Reserves Transferred to Developed	(819)
Price Revisions	(182)
Revisions Due to Plan Changes	(169)
Revisions Due to SEC 5-Year Booking Rule	(709)
Revisions Due to Well Performance and Other	467
Extensions and Discoveries	540
Balance at December 31, 2023	2,713

Proved undeveloped reserves reported at 2,713 Bcfe, a decrease of 872 Bcfe compared to 2022. The decline was primarily driven by a 709 Bcfe SEC 5-Year booking rule adjustment due to changes in the development schedule that shifted previously proved undeveloped reserves outside the SEC's five-year development window. The rule requires that wells not developed within the first five years of their initial booking must be excluded in the current year from the proved reserve calculation. The company's focus on capital efficiency and a maintenance of production program has lowered the rate of inventory consumption and deferred development of certain reserves when compared to prior reserve reports. We anticipate that these undeveloped reserves will be added back in future years.

Proved undeveloped reserves finding and development cost (PUD F&D) are $0.43 per Mcfe and $0.50 per Mcfe when including midstream and water infrastructure costs. PUD F&D excludes plugging and abandonment costs.

The following table presents the summary of proved reserves by category:

Bcfe	Years Ended December 31,
	2023	2022
PDP Reserves	6,028	6,118
PDNP Reserves	-	104
PUD Reserves	2,713	3,585
Total Proved Reserves	8,741	9,807

Note: The proved reserve estimate as of December 31, 2023, was prepared by CNX Resources and audited by Netherland, Sewell & Associates, Inc. The SEC PUD guidelines allow a company to book PUD reserves associated with projects that are to occur within the next five years.

Total Reserves: Proved, Probable, and Possible Reserves (3P) and Other Resource Potential

As of December 31, 2023, CNX has total proved, probable, and possible reserves (also known as "3P reserves") of 11.1 Tcfe, which are comprised of developed reserves and reserves expected to be developed in the company's five-year plan. There are an additional 107 Tcfe of recoverable resources that are economic at the commodity futures strip as of December 30, 2023 in the "Other Resource Potential" that the company expects to develop beyond the five-year plan. This large inventory of proved and probable (2P), 3P and Other 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 and resource, 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	5,166	-	1,814	6,980	1,164	536	8,680	62,223	70,903
Coalbed Methane	522	-	290	812	-	-	812	956	1,768
Utica Shale	335	-	608	943	611	104	1,658	35,084	36,742
Other ⁽¹⁾	5	-	-	5	-	-	5	9,218	9,223
Total, Year End 2023	6,028	-	2,713	8,741	1,775	640	11,156	107,480	118,636
Total, Year End 2022	6,118	104	3,585	9,807	1,227	654	11,687	109,629	121,317

Totals may not add due to rounding.

Note: (1) Other includes Conventional 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).

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, 2023. 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)	2023	2022	2021
Average Henry Hub Price ($/MMBtu)	$ 2.637	$ 6.357	$ 3.598
Future cash inflows	$ 20,281	$ 54,714	$ 31,839
Future production costs	(8,515)	(10,225)	(8,247)
Future development costs (including abandonments)	(1,903)	(2,234)	(1,736)
Future net cash flows (pre-tax)	9,863	42,255	21,856
10% discount factor	(5,662)	(27,754)	(13,775)
PV-10 (Non-GAAP measure) ⁽¹⁾	4,201	14,501	8,081
Undiscounted income taxes	(2,507)	(10,696)	(5,839)
10% discount factor	1,416	6,958	3,640
Discounted income taxes	(1,091)	(3,738)	(2,199)
Standardized GAAP measure	$ 3,110	$ 10,763	$ 5,882

(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.

Supplemental Reserves Information

Securities and Exchange Commission (SEC) pricing as of December 31, 2023:

	SEC	Adjusted
	Pricing ⁽¹⁾	Pricing ⁽²⁾
Benchmark Pricing:
WTI Oil Price ($/Bbl)	$78.22	$73.22
Average Henry Hub Price ($/MMBtu)	$2.64	$2.23
C2+ Natural Gas Liquids ($/Bbl)	$18.54	$18.54
Condensate ($/Bbl)	$65.06	$65.06


(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)	The SEC Pricing is adjusted for quality, hedges, transportation costs, and basis differentials in the calculation of future net cash flows. Henry Hub natural gas price presented in dollars per Mcf.

Summary of Changes in Proved Reserves:

Summary of Changes in Proved Reserves (Bcfe)
Balance at December 31, 2022	9,807
Extensions and Discoveries	582
Revisions	(455)
Production	(560)
Price Adjustments	(465)
Sales of Reserves	(168)
Balance at December 31, 2023	8,741

Note: The proved reserve estimate as of December 31, 2023, was prepared by CNX Resources and audited by Netherland, Sewell & Associates, Inc.

Future Capital Costs for Proved Reserves:

$ millions
Drilling and Completions Capital	$1,158
Midstream and Water Infrastructure Capital	$210
Plugging and Abandonment Costs	$535

Note: Represents the development costs for wells the company expects to turn-in-line over the next five years and plugging and abandonment costs for all proved reserve wells.

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, 2023, CNX had 8.74 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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