CNX Resources Corp.: Q1 FY2026 earnings call

What management said about Q1 FY2026, from the documents filed with the SEC on 30 April 2026: press release. Guidance figures: 4 raised, 6 lowered, 1 new, 9 kept. The quarter’s numbers.

Key takeaways

Net income and diluted EPS rose: Net income was $348.1 million against $196.3 million in the fourth quarter; diluted EPS was $2.18 against $1.28. Source
Adjusted EBITDAX rose to $400 million: Adjusted EBITDAX was $400 million against $292 million, after excluding the unrealized derivative gain of $226 million and stock-based compensation of $6 million. Source
Guidance moved in both directions: Adjusted EBITDAX and free cash flow guidance were lowered, while NGL price and well-count guidance were raised; production volume and total capital expenditure guidance were kept. Source
Daily production rose on flat volumes: Total sales were 152.4 Bcfe, against 152.3 Bcfe in the fourth quarter; average daily production rose to 1,693.0 MMcfe from 1,654.8 MMcfe. Source
Realized gas price rose on NYMEX: NYMEX averaged $5.04 per MMBtu against $3.55; the differential was ($0.55) against ($0.62), and realized gas after cash hedge settlements was $3.15 per Mcf against $2.70. Source
Free cash flow rose to $139 million: Free cash flow was $139 million against $132 million, from operating cash flow of $278 million, capital expenditures of $170 million and asset sale proceeds of $32 million. Source

“Forward market prices, hedged volumes, and hedge prices are as of 4/15/2026. Anticipated hedging activity is not included in projections.”
CNX Resources Corp., press release

Guidance

Area	Period	Figure	Against last quarter
Production volumes Source	2026E	605 - 620 Bcfe	Kept
Liquids share of production Source	2026E	~7% - ~8%	Kept
Natural gas hedged Source	2026E	81%	Kept
NYMEX natural gas price on open volumes Source	2026E	$3.64 per MMBtu	Lowered from $4.07 per MMBtu
Natural gas differential on open volumes Source	2026E	($0.64) per MMBtu	Lowered from ($0.56) per MMBtu
NGL realized price on open volumes Source	2026E	~$24.75 per Bbl	Raised from ~$20.75 per Bbl
Adjusted EBITDAX Source	2026E	$1,265 - $1,315 million	Lowered from $1,310 - $1,360 million
Drilling and completions capital expenditures Source	2026E	$390 - $410 million	Kept
Non-D&C capital expenditures Source	2026E	$150 - $160 million	Kept
Base capital expenditures Source	2026E	$540 - $570 million	Kept
Utica Shale rights payment Source	2026E	$16 million	Kept
Total capital expenditures Source	2026E	556 - 586 million	Kept
Environmental attributes sales, FCF impact Source	2026E	~$70 million	Kept
Free cash flow Source	2026E	~$525 million	Lowered from ~$550 million
Free cash flow per share Source	2026E	~$3.41	Lowered from ~$3.55
Expected asset sales within FCF guidance Source	2026E	~$45 million	Raised from ~$30 million
Turned-in-line wells Source	2026E	34	Raised from 30
Realized natural gas price before hedging, per MMBtu Source	2026E	$3.00	Lowered from $3.51
Projected realized hedging gain or loss Source	CY2026	($193,177) thousand	Raised from ($410,314) thousand
Projected realized hedging gain, Q2 2026 Source	Q2 2026	$48,576 thousand	New

What changed from last quarter

Guidance lowered: 2026 Adjusted EBITDAX guidance moved to $1,265 - $1,315 million from $1,310 - $1,360 million. Source
Guidance lowered: 2026 free cash flow guidance moved to about $525 million from about $550 million. Source
Guidance lowered: 2026 free cash flow per share guidance moved to about $3.41 from about $3.55. Source
Guidance raised: NGL realized price assumption on open 2026 volumes moved to about $24.75 per barrel from about $20.75. Source
Guidance raised: 2026 turned-in-line well count moved to 34 from 30, with the Utica count rising to 7 from 3. Source
Guidance raised: Expected 2026 asset sales within FCF guidance moved to about $45 million from about $30 million. Source
Guidance lowered: NYMEX price assumption on open 2026 volumes moved to $3.64 per MMBtu from $4.07. Source
Guidance kept: Production volume guidance of 605 - 620 Bcfe and natural gas hedged share of 81 percent were unchanged. Source
New: Utica Shale rights across about 23,000 acres beneath the Apex Energy footprint were agreed; the transaction closed in Q1 2026. Source
New: The company issued $500 million of CNX senior notes in the quarter. Source

Earnings and guidance direction

Net income and diluted EPS rose: Net income was $348.1 million against $196.3 million in the fourth quarter; diluted EPS was $2.18 against $1.28. Source
Adjusted EBITDAX rose to $400 million: Adjusted EBITDAX was $400 million against $292 million, after excluding the unrealized derivative gain of $226 million and stock-based compensation of $6 million. Source
Adjusted net income rose to $193 million: Adjusted net income was $193 million against $103 million, after a tax effect of $53 million on pre-tax adjustments of $(208) million. Source
Total revenue rose on gas prices: Total revenue and other operating income was $786.7 million against $610.5 million; natural gas, NGL and oil revenue was $722.0 million against $476.6 million. Source
Guidance moved in both directions: Adjusted EBITDAX and free cash flow guidance were lowered, while NGL price and well-count guidance were raised; production volume and total capital expenditure guidance were kept. Source

Activity by basin and market hub

Q1 wells reached total depth in SWPA: SWPA Marcellus had 14 wells reach total depth, 3 fracked and 6 turned in line; CPA Marcellus had 3 turned in line; Utica had 3 fracked and 3 turned in line, with one rig at period end. Source
Average lateral lengths by basin: Average lateral length was 10,070 feet in SWPA Marcellus, 8,010 feet in CPA Marcellus and 13,590 feet in Utica for the quarter's activity. Source
Gas sales spread across pipeline hubs: Eastern Gas-South took 27 percent of 2026E gas sold at ($0.82) basis, TCO Pool 22 percent at ($0.69) and TETCO M2 26 percent at ($0.85). Source

“(1) Forward market prices for 2026 guidance as of 4/15/2026.”
CNX Resources Corp., press release

Production, products and prices

Daily production rose on flat volumes: Total sales were 152.4 Bcfe, against 152.3 Bcfe in the fourth quarter; average daily production rose to 1,693.0 MMcfe from 1,654.8 MMcfe. Source
Shale gas volumes slipped slightly: Shale sales volumes were 129.8 Bcf against 130.5 Bcf, and coalbed methane volumes were 9.1 Bcf against 9.4 Bcf. Source
NGL sales volumes increased: NGL sales volumes were 13.1 Bcfe against 12.1 Bcfe, and oil and condensate volumes were 0.3 Bcfe against 0.2 Bcfe. Source
Natural gas sales price rose: Average natural gas sales price was $4.74 per Mcfe against $3.12; NGL average was $4.59 against $3.15, and oil and condensate $9.68 against $8.83. Source

Operating costs and expenses

Production costs flat at $1.72: Total production costs were $1.72 per Mcfe, flat on the fourth quarter; transportation, gathering and compression rose to $0.67 from $0.62, while DD&A fell to $0.85 from $0.92. Source
Lease operating expense unchanged: Lease operating expense was $0.14 per Mcfe, unchanged from the fourth quarter, and production, ad valorem and other fees rose to $0.06 from $0.04. Source
Overhead costs fell: Selling, general and administrative costs were $32.2 million against $41.8 million; total operating expense was $311.6 million against $341.4 million. Source
Interest and debt extinguishment costs: Interest expense was $40.5 million against $42.0 million, and a $12.0 million loss on debt extinguishment was recorded in the quarter. Source

Margins and realized pricing

Realized gas price rose on NYMEX: NYMEX averaged $5.04 per MMBtu against $3.55; the differential was ($0.55) against ($0.62), and realized gas after cash hedge settlements was $3.15 per Mcf against $2.70. Source
Operating margin rose to 43%: Operating margin was 43 percent against 28 percent, and cash operating margin was 71 percent against 60 percent, both after the unrealized derivative adjustment. Source
Cash margin before DD&A widened: Production cash margin before DD&A was $2.41 per Mcfe against $1.95, and fully burdened cash margin was $2.33 against $1.64. Source
Fully burdened costs fell: Fully burdened cash costs before DD&A were $0.95 per Mcfe against $1.11 in the fourth quarter. Source

Hedge book and derivative results

NYMEX hedges cover 2026 volumes: Hedged 2026 NYMEX volumes total 356.2 Bcf at $3.55 per Mcf, and Q2 2026 NYMEX hedges total 89.3 Bcf at $3.50, with positions as of 4/15/2026. Source
Realized derivative loss widened: Realized derivative loss was $222 million against $58 million; unrealized gain was $226 million against $130 million. Source
Net derivative gain was small: Gain on commodity derivative instruments was $4 million against $72 million, as the realized loss and unrealized gain largely offset. Source

Cash flow and capital spending

Free cash flow rose to $139 million: Free cash flow was $139 million against $132 million, from operating cash flow of $278 million, capital expenditures of $170 million and asset sale proceeds of $32 million. Source
Operating cash flow dipped on hedges: Net cash from operating activities was $277.5 million against $297.0 million; derivative settlements used $288.4 million, against $18.4 million received in the fourth quarter. Source
Capital spending slightly lower: Capital expenditures were $169.9 million against $174.4 million; asset sale proceeds were $32.4 million, and the Apex acquisition used $10.3 million net of cash acquired. Source

Debt, balance sheet and shareholder returns

Senior notes issued, long-term notes repaid: The company issued $500 million of CNX senior notes and paid $508.0 million of long-term notes in the quarter; cash and cash equivalents were $3.7 million at quarter end. Source
Net debt slightly lower: Net debt was $2,361 million at 31 March 2026, against $2,408 million at 31 December 2025, with cash and restricted cash of $6 million. Source
Share buybacks slowed: Purchases of common stock were $54.0 million against $100.3 million in the fourth quarter; shares withheld for taxes were $15.2 million. Source
Share count behind per-share guidance: The FCF per share guidance uses 141,477,594 shares outstanding at 4/15/2026, plus 12.4 million net shares to settle the remaining convertible notes. Source

Acreage and Apex Utica rights

Marcellus net acreage increased: Total net Marcellus acreage was 556,400 at year-end 2025, against 527,800 a year earlier; Utica net acreage was 611,800, against 605,700. Source
Apex Utica rights on 23,000 acres: Utica rights across about 23,000 acres beneath the Apex Energy footprint were agreed, and are not in the year-end 2025 acreage figures. Source
Environmental attributes add to FCF: Environmental attributes sales are expected to add about $70 million to 2026 free cash flow, unchanged from January. Source

Coming up, as management said on 30 April 2026

2026 well activity plan: Turned-in-line wells planned for 2026 total 34: 24 SWPA Marcellus, 3 CPA Marcellus and 7 Utica. Source
Q2 2026 NYMEX hedges in place: Q2 2026 NYMEX hedges of 89.3 Bcf at $3.50 per Mcf are in place, as of 4/15/2026. Source
Utica rights payment in 2026: A $16 million Utica Shale rights payment is included in 2026 capital expenditure guidance. Source

Figures management reported

Figure	Reported
Total sales volumes (Bcfe) Source	152.4
Average daily production (MMcfe) Source	1,693.0
Realized natural gas price per Mcf Source	$3.15
Average sales price, gas, NGL and oil incl. cash settlement (per Mcfe) Source	$3.28
NGL average sales price (per Mcfe) Source	$4.59
Oil and condensate average sales price (per Mcfe) Source	$9.68
Lease operating expense (per Mcfe) Source	$0.14
Total production costs (per Mcfe) Source	$1.72
Capital expenditures Source	$169.9 million
Purchases of common stock Source	$54.0 million

Other quarters

Summarised with AI from the documents the company filed with the SEC. Every point is checked against the filing before it is shown: management’s own words word for word, figures against the line or table row they come from. A point that fails the check is left out. Source opens the filing at that line.

As filed with the SEC

Open the filing on EDGAR

1Q 2026 Earnings Results &
Supplemental Information of CNX Resources
TABLE OF CONTENTS:	Page:
Production Volumes and Activity Summary........................................................................................................................	2
Hedge Volumes and Pricing…...........................................................................................................................................	3
Gas Hedging Gain/Loss Projections and Actuals..............................................................................................................	4
Consolidated Statements of Income..................................................................................................................................	5
Consolidated Balance Sheets............................................................................................................................................	6
Consolidated Statements of Cash Flows….......................................................................................................................	7
Market Mix and Natural Gas Price Reconciliation…..........................................................................................................	8
Price and Cost Data (Per Mcfe).........................................................................................................................................	9
Guidance…........................................................................................................................................................................	10
Year End 2025 Acreage and Undeveloped Location Update…......................................................................................…	11
Definitions..........................................................................................................................................................................	12
Sales of Natural Gas, NGL and Oil, including Cash Settlements and Natural Gas, NGL and Oil Production Costs.........	13
Quarterly Adjusted EBITDAX and Adjusted Net Income....................................................................................................	14
Operating Margin...............................................................................................................................................................	15
Cash Operating Margin......................................................................................................................................................	16
Net Debt and Adjusted EBITDAX TTM..............................................................................................................................	17
Free Cash Flow..................................................................................................................................................................	18
Risk Factors.......................................................................................................................................................................	19

NOTE: Please note that CNX is unable to provide a reconciliation of non-GAAP projected financial results contained in this presentation, including the non-GAAP measures referenced above, to their respective comparable financial measure calculated in accordance with GAAP. This is due to our inability to calculate the comparable GAAP projected metrics, including operating income, net cash provided by operating activities and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.

PRODUCTION VOLUMES
GAS			Q1-2026		Q4-2025		Q3-2025		Q2-2025			Q1-2025
Shale Sales Volumes (Bcf)			129.8		130.5		139.2		146.9			126.0
CBM Sales Volumes (Bcf)			9.1		9.4		9.7		9.4			9.3
Other Sales Volumes (Bcf)			0.1		0.1		0.1		-			0.1
LIQUIDS*
NGLs Sales Volumes (Bcfe)			13.1		12.1		12.0		11.1			12.2
Oil and Condensate Sales Volumes (Bcfe)			0.3		0.2		0.3		0.2			0.2
TOTAL (Bcfe)			152.4		152.3		161.3		167.6			147.8
Average Daily Production (MMcfe)			1,693.0		1,654.8		1,753.3		1,841.8			1,642.3
* NGLs, Oil and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
Q1 2026 ACTIVITY SUMMARY			TD		Frac		TIL		Average Lateral Length			Rigs at Period End
SWPA	Marcellus		14		3		6		10,070			-
Utica		-		-		-		-		-
CPA	Marcellus		-		-		3		8,010			-
Utica		-		3		3		13,590			1
Total			14		6		12						1
(1) Measured in lateral feet from perforation to perforation.

	Q2 2026	2026	2027	2028
NATURAL GAS HEDGE VOLUMES AND PRICING
NYMEX Hedges
Volumes (Bcf)	89.3	356.2	259.7	102.8
Average Prices ($/Mcf)	$3.50	$3.55	$4.17	$4.03
Physical Fixed Price Sales and Index Hedges
Volumes (Bcf)	25.9	103.4	140.6	38.9
Average Prices ($/Mcf)	$2.64	$2.64	$3.31	$3.11
Total Volumes Hedged (Bcf)	115.1	459.6	400.3	141.6
NYMEX + Basis (fully-covered volumes)
Volumes (Bcf)	110.8	445.6	400.3	141.6
Average Prices ($/Mcf)	$2.71	$2.74	$3.31	$3.25
NYMEX Hedges Exposed to Basis
Volumes (Bcf)	4.36	14.0	-	-
Average Prices ($/Mcf)	$3.50	$3.54	-	-
Total Volumes Hedged (Bcf)	115.1	459.6	400.3	141.6
Estimated Conversion Factor	1.060	1.063	1.064	1.060
(1) Hedge positions as of 4/15/2026.
(2) Excludes basis hedges in excess of NYMEX hedges of 1.9 Bcf and 58.6 Bcf for 2027 and 2028, respectively.
(3) Includes the impact of NYMEX and basis-only hedges as well as physical sales agreements.
(4) To convert Bcf to TBtu, multiply by conversion factor; to convert $/Mcf to $/MMBtu, divide by conversion factor.

	Q2 2026							CY2026
	Hedged Volumes		Wtd. Avg.		Average	Forecasted		Hedged Volumes		Wtd. Avg.		Average	Forecasted
HEDGING GAIN/LOSS PROJECTIONS
($/MMBtu)	(000 MMBtu)		Hedged Price		Forward Market	Gain/(Loss)($ in 000s)		(000 MMBtu)		Hedged Price		Forward Market	Gain/(Loss)($ in 000s)
NYMEX		94,640		$3.30	$2.82		$45,593		378,670		$3.34	$3.64		($105,482)
Index		27,300		$2.49	$2.10	$10,699			109,500		$2.49	$2.93	($48,446)
Basis:
Eastern Gas-South (DOM)		27,300		($0.88)	($0.83)		($1,599)		110,060		($0.88)	($0.78)		($9,225)
TCO Pool (TCO)		12,058		($0.74)	($0.58)		($1,968)		48,643		($0.74)	($0.57)		($7,079)
Michcon (NMC)		8,190		($0.19)	($0.29)		$771		32,850		($0.19)	($0.37)		$5,761
TETCO M3 (TMT)	-		-		($0.73)	-		-		-		$0.43	-
TETCO M2 (BM2)		26,618		($1.01)	($0.82)		($4,920)		106,763		($1.01)	($0.73)		($28,707)
STA 165 (TSD)	-		-		($0.67)		$0	-		-		$0.22	-
Total Financial Basis Hedges		74,165					($7,716)		298,315					($39,249)
Total Projected Realized Gain / (Loss)							$48,576							($193,177)
Note: Forward market prices, hedged volumes, and hedge prices are as of 4/15/2026. Anticipated hedging activity is not included in projections.
(1) April 2026 prices are settled.
(2) Forecasted Gain/(Loss) amounts are based on sum of current monthly hedge positions vs. strip.

Actual Change in Derivatives
(Dollars in millions)	Q1 2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Realized (Loss) Gain		($222)		($58)		$22		($35)		($110)
Unrealized Gain (Loss)	226		130		110		456		(418)
Gain (Loss) on Commodity Derivative Instruments		$4		$72		$132		$421		$(528)

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Dollars in thousands, except per share data
Revenue and Other Operating Income:	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Natural Gas, NGL and Oil Revenue		$722,044		$476,615		$400,990		$485,029		$551,094
Gain (Loss) on Commodity Derivative Instruments		3,981		72,065		131,695		421,121		(528,220)
Purchased Gas Revenue		12,687		14,365		9,026		10,408		11,550
Other Revenue and Operating Income		47,942		47,439		42,129		45,864		47,964
Total Revenue and Other Operating Income	786,654		610,484		583,840		962,422		82,388
Costs and Expenses:
Operating Expense
Lease Operating Expense		21,770		20,700		27,127		26,256		23,333
Transportation, Gathering and Compression		102,401		93,939		97,053		96,953		95,159
Production, Ad Valorem, and Other Fees		8,789		6,534		7,725		9,668		7,273
Depreciation, Depletion and Amortization		134,613		145,134		149,323		152,595		127,062
Exploration and Production Related Other Costs		4,177		5,008		1,656		1,770		2,082
Purchased Gas Costs		12,253		13,581		8,455		9,402		11,209
Selling, General, and Administrative Costs		32,245		41,846		30,375		29,068		39,013
Other Operating (Income) Expense	(4,622)		14,640		19,178		21,014		14,080
Total Operating Expense		311,626		341,382		340,892		346,726		319,211
Other Expense (Income)
Other Expense		509		4,288		1,752		3,729		3,947
Gain on Asset Sales and Abandonments, net		(6,365)		(2,410)		(67,460)		(17,715)		(9,583)
Loss on Debt Extinguishment		12,009		842		-		-		-
Interest Expense	40,470		41,975		42,964		44,041		41,612
Total Other Expense (Income)		46,623		44,695		(22,744)		30,055		35,976
Total Costs and Expenses	358,249		386,077		318,148		376,781		355,187
Earnings (Loss) Before Income Tax		428,405		224,407		265,692		585,641		(272,799)
Income Tax Expense (Benefit)	80,258		28,154		63,589		153,120		(75,084)
Net Income (Loss)		$348,147		$196,253		$202,103		$432,521		$(197,715)
Earnings (Loss) per Share
Basic		$2.45		$1.45		$1.45		$3.02		$(1.34)
Diluted		$2.18		$1.28		$1.21		$2.53		$(1.34)
Weighted-Average Shares Outstanding	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Weighted-Average Shares of Common Stock Outstanding	142,202,197		135,514,779		139,251,482		143,429,950		147,778,141
Effect of Diluted Shares*	18,086,409		19,021,107		28,333,716		28,316,646		-
Weighted-Average Diluted Shares of Common Stock Outstanding	160,288,606		154,535,886		167,585,198		171,746,596		147,778,141
*During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards and the potential share settlement impact related to CNX's Convertible Notes are antidilutive.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
Dollars in thousands	31-Mar-26		31-Dec-25		30-Sep-25		30-Jun-25		31-Mar-25
ASSETS
Current Assets:
Cash and Cash Equivalents		$3,748		$779		$4,735		$3,391		$2,615
Restricted Cash	2,428		12,685		10,168		10,072		10,272
Accounts and Notes Receivable
Trade, net	209,523		264,658		141,264		180,152		246,765
Other Receivables, net	27,928		61,249		56,596		37,166		51,560
Supplies Inventories	30,108		26,201		30,822		39,318		27,591
Derivative Instruments	164,572		106,068		100,076		107,401		68,860
Prepaid Expenses	20,025		18,697		17,234		16,725		17,767
Total Current Assets	458,332		490,337		360,895		394,225		425,430
Property, Plant and Equipment:
Property, Plant and Equipment	14,222,717		14,057,224		13,839,517		13,771,249		13,667,826
Less - Accumulated Depreciation, Depletion and Amortization	6,310,588		6,193,871		6,054,758		5,912,645		5,771,499
Total Property, Plant and Equipment - Net	7,912,129		7,863,353		7,784,759		7,858,604		7,896,327
Other Non-Current Assets:
Operating Lease Right-of-Use Assets	137,987		150,310		167,893		91,546		85,666
Derivative Instruments	184,261		134,396		118,387		167,561		165,908
Goodwill	323,314		323,314		323,314		323,314		323,314
Other Intangible Assets	55,695		57,333		58,971		60,609		62,247
Restricted Cash	-		-		2,430		2,428		-
Other Non-Current Assets	59,465		75,403		87,469		89,580		87,817
Total Other Non-Current Assets	760,722		740,756		758,464		735,038		724,952
TOTAL ASSETS		$9,131,183		$9,094,446		$8,904,118		$8,987,867		$9,046,709
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable		$162,043		$158,811		$110,649		$120,019		$144,376
Derivative Instruments	244,321		377,945		316,729		403,112		770,980
Current Portion of Finance Lease Obligations	5,106		5,095		5,080		4,338		4,335
Current Portion of Long-Term Debt	208,437		208,095		329,378		328,837		328,300
Current Portion of Operating Lease Obligations	47,486		48,453		48,140		47,819		50,082
Other Accrued Liabilities	260,356		325,976		255,313		293,558		284,820
Total Current Liabilities	927,749		1,124,375		1,065,289		1,197,683		1,582,893
Non-Current Liabilities:
Long-Term Debt	2,158,416		2,213,264		2,247,199		2,286,855		2,353,350
Finance Lease Obligations	23,716		24,991		26,209		19,229		20,304
Operating Lease Obligations	93,438		104,955		122,477		46,424		37,834
Derivative Instruments	107,944		158,368		251,206		342,613		439,769
Deferred Income Taxes	936,137		857,367		836,354		761,490		604,526
Asset Retirement Obligations	163,692		163,051		124,460		125,504		124,253
Other Non-Current Liabilities	93,511		111,059		115,351		115,356		113,006
Total Non-Current Liabilities	3,576,854		3,633,055		3,723,256		3,697,471		3,693,042
TOTAL LIABILITIES	4,504,603		4,757,430		4,788,545		4,895,154		5,275,935
Stockholders' Equity:
Common Stock	1,420		1,427		1,360		1,420		1,456
Capital in Excess of Par Value	2,356,077		2,357,039		2,254,021		2,298,970		2,324,116
Preferred Stock	-		-		-		-		-
Retained Earnings	2,274,690		1,984,229		1,865,695		1,797,896		1,450,844
Accumulated Other Comprehensive Loss	(5,607)		(5,679)		(5,503)		(5,573)		(5,642)
TOTAL STOCKHOLDERS' EQUITY	4,626,580		4,337,016		4,115,573		4,092,713		3,770,774
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$9,131,183		$9,094,446		$8,904,118		$8,987,867		$9,046,709

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Dollars in thousands
Cash Flows from Operating Activities:	Q1-2026	Q4-2025	Q3-2025	Q2-2025	Q1-2025
Net Income (Loss)	$348,147	$196,253	$202,103	$432,521	($197,715)
Depreciation, Depletion and Amortization	134,613	145,134	149,323	152,595	127,062
Amortization of Deferred Financing Costs	2,500	2,650	2,713	2,701	2,668
Stock-Based Compensation	5,685	4,614	5,165	5,084	8,816
Gain on Asset Sales and Abandonments, net	(6,365)	(2,410)	(67,460)	(17,715)	(9,583)
Loss on Debt Extinguishment	12,009	842	-	-	-
(Gain) Loss on Commodity Derivative Instruments	(3,981)	(72,065)	(131,695)	(421,121)	528,220
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments	(288,435)	18,441	10,405	(84,097)	(88,285)
Deferred Income Taxes	78,743	21,070	74,838	156,938	(91,636)
Other	463	(4)	1,351	(605)	1,097
Changes in Operating Assets:
Accounts and Notes Receivable	62,958	(115,678)	39,266	81,874	(72,103)
Supplies Inventories	(3,907)	4,621	8,496	(11,727)	(13,019)
Prepaid Expenses	(1,329)	(1,463)	(509)	1,042	(2,108)
Changes in Other Assets	14,932	(350)	(291)	(103)	23,277
Changes in Operating Liabilities:
Accounts Payable	(9,444)	39,583	(17,917)	(13,453)	13,396
Accrued Interest	(25,451)	20,452	(21,309)	20,335	(14,419)
Other Operating Liabilities	(26,162)	39,258	(20,769)	(24,184)	24,565
Changes in Other Liabilities	(17,463)	(3,900)	51	2,407	(24,577)
Net Cash Provided by Operating Activities	277,513	297,048	233,761	282,492	215,656
Cash Flows from Investing Activities:
Capital Expenditures	(169,906)	(174,414)	(75,544)	(113,565)	(131,465)
Proceeds from Asset Sales	32,428	2,449	67,793	20,783	16,630
Investments in Equity Affiliates	(565)	7,322	-	(2,140)	(1,163)
Apex Acquisition (Net of Cash Acquired)	(10,255)	-	-	-	(517,599)
Net Cash Used in Investing Activities	(148,298)	(164,643)	(7,751)	(94,922)	(633,597)
Cash Flows from Financing Activities:
Payments on Long-Term Notes	(507,965)	-	-	-	-
Proceeds from CNXM Revolving Credit Facility Borrowings	134,650	86,300	72,500	88,175	92,250
Repayments of CNXM Revolving Credit Facility Borrowings	(62,400)	(74,050)	(74,000)	(88,875)	(85,600)
Proceeds from CNX Revolving Credit Facility Borrowings	496,450	352,500	436,350	365,300	772,950
Repayments of CNX Revolving Credit Facility Borrowings	(620,150)	(399,750)	(475,550)	(431,900)	(463,350)
Proceeds from Issuance of CNX Senior Notes	500,000	-	-	-	198,500
Payments on Other Debt	(1,265)	(1,375)	(1,181)	(948)	(960)
Proceeds from Issuance of Common Stock	1,506	1,108	56	110	820
Shares Withheld for Taxes	(15,216)	(167)	(348)	(406)	(13,086)
Purchases of Common Stock	(54,039)	(100,335)	(182,374)	(115,714)	(125,138)
Debt Issuance and Financing Fees	(8,074)	(505)	(21)	(308)	(631)
Net Cash (Used in) Provided by Financing Activities	(136,503)	(136,274)	(224,568)	(184,566)	375,755
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(7,288)	(3,869)	1,442	3,004	(42,186)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	13,464	17,333	15,891	12,887	55,073
Cash, Cash Equivalents and Restricted Cash at End of Period	$6,176	$13,464	$17,333	$15,891	$12,887

	2026E
	Gas Sold (%)	Basis
MARKET MIX AND NATURAL GAS PRICE RECONCILIATION
Eastern Gas-South	27%	($0.82)
ETNG Mainline	4%	($0.58)
TCO Pool	22%	($0.69)
TETCO ELA & WLA	2%	($0.43)
TETCO M3	2%	$0.00
TETCO M2	26%	($0.85)
Michcon	8%	($0.38)
Physical basis sales	9%	($0.31)
Weighted Average Basis	100%	($0.64)
NYMEX		$3.64
Weighted Average Basis (Not considering hedging)		($0.64)
Realized Price (per MMBtu)		$3.00
Conversion Factor (MMBtu/Mcf)		1.063
Realized Price Before Financial Hedging (per Mcf)		$3.19
(1) Individual market percentages exclude physical basis sales, which are shown separately.
(2) Reflects actual realized basis for three months ended March 31; April - December forward market basis prices as of 4/15/2026.

	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
PRICE AND COST DATA (PER MCFE) - NON-GAAP
Average Sales Price - Natural Gas		$4.74		$3.12		$2.43		$2.84		$3.66
Average Gain (Loss) on Natural Gas Commodity Derivative Instruments - Cash Settlement	($1.59)		($0.42)		$0.15		($0.23)		($0.81)
Average Sales Price - Oil and Condensate*		$9.68		$8.83		$9.49		$8.74		$9.61
Average Sales Price - NGLs*		$4.59		$3.15		$3.04		$3.58		$4.42
Average Sales Price of Natural Gas, NGL and Oil, including Cash Settlement		$3.28		$2.75		$2.62		$2.68		$2.99
Lease Operating Expense (LOE)		$0.14		$0.14		$0.17		$0.16		$0.16
Production, Ad Valorem, and Other Fees		$0.06		$0.04		$0.05		$0.05		$0.05
Transportation, Gathering and Compression		$0.67		$0.62		$0.60		$0.58		$0.64
Depreciation, Depletion and Amortization (DD&A)		$0.85		$0.92		$0.89		$0.88		$0.83
Total Natural Gas, NGL and Oil Production Costs		$1.72		$1.72		$1.71		$1.67		$1.68
Total Natural Gas, NGL and Oil Production Cash Costs, before DD&A		$0.87		$0.80		$0.82		$0.79		$0.85
Natural Gas, NGL and Oil Production Cash Margin, before DD&A		$2.41		$1.95		$1.80		$1.89		$2.14
Fully Burdened Cash Costs, before DD&A		$0.95		$1.11		$1.09		$1.05		$1.11
Fully Burdened Cash Margin, before DD&A		$2.33		$1.64		$1.53		$1.63		$1.88
Note: "Total Natural Gas, NGL and Oil Production Costs" excludes Selling, General, and Administration and Other Operating Expenses.
*NGLs, Oil, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
(1) Fully burdened cash costs include production cash costs, selling, general and administrative (SG&A) cash costs, other operating cash expense, other cash expense (income), other revenue and operating income, and cash interest expense. Q1 2026, Q4 2025, Q3 2025, Q2 2025 and Q1 2025 total fully burdened cash costs exclude a (gain)/loss on asset sales of ($0.04) per Mcfe, ($0.02) per Mcfe,($0.42) per Mcfe, ($0.11) per Mcfe and $0.06 per Mcfe, respectively. Q1 2026, Q4 2025, Q3 2025, Q2 2025 and Q1 2025 exclude unrealized losses on interest rate swaps and noncash amortization of $0.02 per Mcfe, $0.02 per Mcfe, $0.02 per Mcfe, $0.02 per Mcfe and $0.02 per Mcfe, respectively. Q1 2026, Q4 2025, Q3 2025, Q2 2025 and Q1 2025, exclude loss on debt extinguishment and inventory adjustments of $0.08 per Mcfe, $0.01 per Mcfe, $0.00 per Mcfe, $0.00 per Mcfe and $0.01 per Mcfe, respectively.
Natural Gas Price Reconciliation	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
NYMEX Natural Gas ($/MMBtu)		$5.04		$3.55		$3.07		$3.44		$3.65
Average Differential	(0.55)		(0.62)		(0.77)		(0.76)		(0.26)
BTU Conversion (MMBtu/Mcf)*	0.25		0.19		0.12		0.15		0.27
Average Gain (Loss) on Natural Gas Commodity Derivative Instruments - Cash Settlement	(1.59)		(0.42)		0.15		(0.23)		(0.81)
Realized Natural Gas Price per Mcf		$3.15		$2.70		$2.57		$2.61		$2.85
*Conversion factor		1.06		1.07		1.05		1.06		1.08

	PREVIOUS			UPDATED
GUIDANCE
($ in millions)	2026E			2026E
	Low		High	Low		High
Production Volumes (Bcfe)	605	-	620	605	-	620
% Liquids	~7%	-	~8%	~7%	-	~8%
% of Natural Gas Hedged			81%			81%
Prices on Open Volumes
Natural Gas NYMEX ($/MMBtu)			$4.07			$3.64
Natural Gas Differential ($/MMBtu)			($0.56)			($0.64)
NGL Realized Price ($/Bbl)	~$20.75			~$24.75
($ in millions)
Adjusted EBITDAX	$1,310	-	$1,360	$1,265	-	$1,315
Capital Expenditures
Drilling & Completions (D&C)	$390	-	$410	$390	-	$410
Non-D&C	$150	-	$160	$150	-	$160
Base Capital Expenditures	$540	-	$570	$540	-	$570
Utica Shale rights payment	$16	-	$16	$16	-	$16
Total Capital Expenditures	556	-	586	556	-	586
Environmental Attributes Sales Free Cash Flow (FCF) Impact	~$70			~$70
Free Cash Flow (FCF)(2)(3)	~$550			~$525
FCF Per Share(2)(3)(4)	~$3.55			~$3.41
(1) Forward market prices for 2026 guidance as of 4/15/2026.
(2) Non-GAAP measures. See “Non-GAAP Financial Measures” for definitions.
(3) Guidance for FCF includes approximately $45 million in expected asset sales in 2026 and approximately $20 million from the sale of 45Z tax credits for 8 months of remediation activities in 2025.
(4) Previous guidance for 2026 FCF per share based on shares outstanding of 142,402,658, as of 1/23/2026, plus 12.4 million net shares expected to be issued to settle the remaining CNX Convertible Notes. Updated guidance for 2026 FCF per share based on shares outstanding of 141,477,594, as of 4/15/2026, plus 12.4 million net shares expected to be issued to settle the remaining CNX Convertible Notes.

2026E ACTIVITY SUMMARY				TIL		Average Lateral Length
SWPA		Marcellus		24		13,750
CPA		Marcellus		3		7,880
	Utica		7		13,400
Total				34
(1) Measured in lateral feet from perforation to perforation.

YEAR END 2025 ACREAGE AND UNDEVELOPED LOCATION UPDATE

YE2024 MARCELLUS ACREAGE				YE2025 MARCELLUS ACREAGE
SWPA	Central	Greater	TOTAL SWPA	SWPA	Central	Greater	TOTAL SWPA
Total Net Acres	108,000	26,600	134,600	Total Net Acres	106,400	26,300	132,700
Net Developed Acres	66,800	3,600	70,400	Net Developed Acres	70,900	3,600	74,600
Net Undeveloped Acres	41,200	23,000	64,200	Net Undeveloped Acres	35,500	22,700	58,100
WV	SHR/PENS	East	TOTAL WV	WV	SHR/PENS	East	TOTAL WV
Total Net Acres	14,300	10,900	83,900	Total Net Acres	14,300	8,900	81,900
Net Developed Acres	10,900	800	11,700	Net Developed Acres	10,900	800	11,700
Net Undeveloped Acres	3,400	10,100	72,200	Net Undeveloped Acres	3,400	8,100	70,200
CPA	South	North	TOTAL CPA	CPA	South	North	TOTAL CPA
Total Net Acres	112,500	87,200	301,000	Total Net Acres	151,100	87,200	340,100
Net Developed Acres	6,400	1,000	7,300	Net Developed Acres	21,500	1,000	22,400
Net Undeveloped Acres	106,100	86,200	293,700	Net Undeveloped Acres	129,600	86,200	317,700
OH			TOTAL OH	OH			TOTAL OH
Total Net Acres			8,300	Total Net Acres			1,700
Net Developed Acres			200	Net Developed Acres			200
Net Undeveloped Acres			8,100	Net Undeveloped Acres			1,500
Total Net Acres			527,800	Total Net Acres			556,400
YE2024 UTICA ACREAGE				YE2025 UTICA ACREAGE
SWPA	Central	Greater	TOTAL SWPA	SWPA	Central	Greater	TOTAL SWPA
Total Net Acres	113,900	56,000	169,800	Total Net Acres	113,000	56,100	169,100
Net Developed Acres	8,200	-	8,200	Net Developed Acres	8,200	-	8,200
Net Undeveloped Acres	105,700	56,000	161,600	Net Undeveloped Acres	104,800	56,100	160,900
WV	SHR/PENS	East	TOTAL WV	WV	SHR/PENS	East	TOTAL WV
Total Net Acres	11,600	84,300	133,600	Total Net Acres	11,400	82,500	131,600
Net Developed Acres	-	-	-	Net Developed Acres	-	-	-
Net Undeveloped Acres	11,600	84,300	133,600	Net Undeveloped Acres	11,400	82,500	131,600
CPA	South	North	TOTAL CPA	CPA	South	North	TOTAL CPA
Total Net Acres	113,800	86,900	238,800	Total Net Acres	126,200	87,000	247,700
Net Developed Acres	3,400	200	3,600	Net Developed Acres	8,300	200	8,400
Net Undeveloped Acres	110,400	86,700	235,200	Net Undeveloped Acres	117,900	86,800	239,300
OH	Dry		TOTAL OH	OH	Dry		TOTAL OH
Total Net Acres	15,600		63,500	Total Net Acres	15,400		63,400
Net Developed Acres	13,200		13,200	Net Developed Acres	13,200		13,200
Net Undeveloped Acres	2,400		50,300	Net Undeveloped Acres	2,200		50,200
Total Net Acres			605,700	Total Net Acres			611,800
Note: The YE2025 acreage does not include the Utica Shale rights across approximately 23,000 acres that CNX agreed to acquire beneath the Apex Energy footprint since the transaction closed in Q1 2026.
Acres by type curve area do not equal total acres because some CNX-controlled acres fall outside of identified type curve areas. The table includes results of leasing activity and expirations; and future development, lateral lengths and inter-lateral spacing, will ultimately vary as the assets are developed.

Non-GAAP Measures (Definitions, Purpose, and Reconciliations)

CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the company. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that these financial measures are useful to an investor in evaluating CNX because (i) analysts utilize these metrics when evaluating company performance and have requested this information as of a recent practicable date, (ii) these metrics are widely used to evaluate a company’s operating performance, and (iii) we want to provide updated information to investors. Investors should not view these metrics as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.

Definitions: EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDAX is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes, depreciation, depletion and amortization, and exploration. Adjusted EBITDAX is defined as EBITDAX after adjusting for the discrete items listed below. Although EBIT, EBITDAX, and adjusted EBITDAX are not measures of performance calculated in accordance with generally accepted accounting principles, management believes that they are useful to an investor in evaluating CNX Resources because they are widely used to evaluate a company's operating performance. We exclude stock-based compensation from adjusted EBITDAX because we do not believe it accurately reflects the actual operating expense incurred during the relevant period and may vary widely from period to period irrespective of operating results. Investors should not view these metrics as a substitute for measures of performance that are calculated in accordance with generally accepted accounting principles. In addition, because all companies do not calculate EBIT, EBITDAX or adjusted EBITDAX identically, the presentation here may not be comparable to similarly titled measures of other companies. Sales of natural gas, NGL and oil, including cash settlements excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Natural gas, NGL and oil production costs excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations. Adjusted Net Income (Loss) is defined as net income after adjusting for the discrete items listed below as well as the tax effectiveness. Operating Margins are defined as adjusted EBIT divided by Total Revenue after adjusting for unrealized (gain) loss on commodity derivative instruments. Adjusted Trailing-Twelve-Months (TTM) EBITDAX is defined as EBITDAX over the trailing-twelve-months after adjusting for the discrete items listed below. Cash Operating Margins are defined as adjusted EBITDA divided by total Revenue after adjusting for unrealized (gain) loss on commodity derivative instruments. Net Debt is defined as total long-term debt minus cash, cash equivalents, and restricted cash. Adjusted Net Debt is defined as total long-term debt plus the historical impact of recent accounting pronouncement, minus cash, cash equivalents, and restricted cash. Free Cash Flow (FCF) is defined as net cash provided by operating activities minus capital expenditures plus proceeds from asset sales and minus investments in equity affiliates.

Reconciliations of EBIT, EBITDAX, adjusted EBITDAX, adjusted EBIT, adjusted EBITDA, sales of natural gas, NGL and oil, including cash settlements, natural gas, NGL and oil production costs, adjusted net income, operating margins, cash operating margins, net debt, adjusted net debt, adjusted TTM EBITDAX and FCF to the most directly comparable GAAP financial measures are as follows:

Non-GAAP Measures
Sales of Natural Gas, NGL and Oil, including cash settlements excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note 21 - Segment Information of the Notes to the Audited Consolidated Financial Statements in Item 8 of CNX's 2025 Annual Report on Form 10-K as filed with the SEC on February 10, 2026). These expenses include, but are not limited to, interest expense and other corporate expenses such as selling, general and administrative costs in the current periods presented.
(Dollars in millions)	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Total Revenue and Other Operating Income		$787		$611		$584		$962		$82
(Deduct) Add:
Purchased Gas Revenue	(13)		(15)		(9)		(10)		(11)
Unrealized (Gain) Loss on Commodity Derivative Instruments		(226)		(130)		(110)	(456)			418
Other Revenue and Operating Income	(48)		(47)		(42)		(46)		(48)
Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure		$500		$419		$423		$450		$441
Total Operating Expense		$312		$342		$341		$346		$319
(Deduct):
Depreciation, Depletion and Amortization (DD&A) - Corporate	(6)		(5)		(5)		(4)		(6)
Exploration and Production Related Other Costs	(4)		(5)		(2)		(2)		(2)
Purchased Gas Costs	(12)		(14)		(9)		(9)		(11)
Selling, General and Administrative Costs	(32)		(42)		(30)		(29)		(39)
Other Operating Income (Expense)	4		(15)		(19)		(21)		(14)
Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure		$262		$261		$276		$281		$247

Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.

Non-GAAP Measures
EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDAX is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes, depreciation, depletion and amortization, and exploration. Adjusted EBITDAX is defined as EBITDAX after adjusting for the discrete items listed below.
(Dollars in millions)	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Net Income (Loss)		$348		$196		$202		$433		($198)
Interest Expense	41		42		43		43		42
Interest Income	-		-		-		(1)		-
Income Tax Expense (Benefit)	80		28		64		153		(75)
Earnings (Loss) Before Interest & Taxes (EBIT)	469		266		309		628		(231)
Depreciation, Depletion & Amortization		135		145	149		153			127
Exploration Expense		4		5	2		2			2
Earnings (Loss) Before Interest, Taxes, DD&A and Exploration (EBITDAX)		$608		$416		$460		$783		($102)
Adjustments:
Unrealized (Gain) Loss on Commodity Derivative Instruments		(226)		(130)	(110)		(456)			418
Gain on Non-Core Asset Sale		-		-	(57)		-			-
Stock-Based Compensation	6		5		5		5		9
Loss on Debt Extinguishment	12		1		-		-		-
Total Pre-tax Adjustments	(208)		(124)		(162)		(451)		427
Adjusted EBITDAX		$400		$292		$298		$332		$325
Adjusted Net Income is defined as net income after adjusting for the discrete items listed below as well as the related tax effect.
(Dollars in millions)	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Net Income (Loss) from EBITDAX Reconciliation		$348		$196		$202		$433		($198)
Adjustments:
Total Pre-tax Adjustments from EBITDAX Reconciliation	(208)		(124)		(162)		(451)		427
Tax Effect of Adjustments	53		31		42		119		(113)
Adjusted Net Income		$193		$103		$82		$101		$116

Non-GAAP Measures
Operating Margin: Adjusted EBIT divided by Total Revenue and Other Operating Income after adjusting for unrealized (gain) loss on commodity derivative instruments.
(Dollars in millions)	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Total Revenue and Other Operating Income		$787		$611		$584		$962		$82
Net Income (Loss)		$348		$196		$202		$433		($198)
Interest Expense		41		42		43		43		42
Interest Income		-		-		-		(1)		-
Income Tax Expense (Benefit)		80		28		64		153		(75)
Earnings (Loss) Before Interest & Taxes (EBIT)		469		266		309		628		(231)
Depreciation, Depletion & Amortization		135		145		149		153		127
Earnings (Loss) Before Interest, Taxes, DD&A (EBITDA)		$604		$411		$458		$781		($104)
Adjustments:
Unrealized (Gain) Loss on Commodity Derivative Instruments		($226)		($130)		($110)		($456)		$418
Total Adjustments		($226)		($130)		($110)		($456)		$418
Total Revenue and Other Operating Income Minus Unrealized (Gain) Loss on Commodity Derivative Instruments		$561		$481		$474		$506		$500
Adjusted EBIT		$243		$136		$199		$172		$187
Operating Margin	43%		28%		42%		34%		37%

Non-GAAP Measures
Cash Operating Margin: Adjusted EBITDA divided by Total Revenue and Other Operating Income after adjusting for unrealized (gain) loss on commodity derivative instruments, stock based compensation and the other discrete items listed below.
(Dollars in millions)	Q1-2026		Q4-2025		Q3-2025		Q2-2025		Q1-2025
Total Revenue and Other Operating Income		$787		$611		$584		$962		$82
Net Income (Loss)		$348		$196		$202		$433		($198)
Interest Expense		41		42		43		43		42
Interest Income		-		-		-		(1)		-
Income Tax Expense (Benefit)		80		28		64		153		(75)
Earnings (Loss) Before Interest & Taxes (EBIT)		469		266		309		628		(231)
Depreciation, Depletion & Amortization		135		145		149		153		127
Earnings (Loss) Before Interest, Taxes, DD&A (EBITDA)		$604		$411		$458		$781		($104)
Adjustments:
Unrealized (Gain) Loss on Commodity Derivative Instruments		$(226)		$(130)		($110)		($456)		$418
Gain on Non-Core Asset Sale		-		-		(57)		-		-
Stock-Based Compensation		6		5		5		5		9
Loss on Debt Extinguishment		12		1		-		-		-
Total Adjustments		($208)		($124)		($162)		($451)		$427
Total Revenue and Other Operating Income Minus Unrealized (Gain) Loss on Commodity Derivative Instruments		$561		$481		$474		$506		$500
Adjusted EBITDA		$396		$287		$296		$330		$323
Cash Operating Margin	71%		60%		62%		65%		65%

Non-GAAP Measures
Management uses net debt to determine the company's outstanding debt obligations that would not be readily satisfied by its cash, cash equivalents, and restricted cash on hand. Management believes that using net debt is useful to investors in determining the company's leverage ratio since the company could choose to use its cash, cash equivalents, and restricted cash to retire debt.
Net Debt: Total long-term debt minus cash, cash equivalents, and restricted cash.
Adjusted Net Debt: Total long-term debt, plus the historical impact of accounting pronouncement, minus cash, cash equivalents, and restricted cash.
(Dollars in millions)
Net Debt	31-Mar-26	31-Dec-25	31-Dec-24	31-Dec-23	31-Dec-22	31-Dec-21	31-Dec-20	30-Sep-20
Total Long-Term Debt (GAAP)	$2,367	$2,421	$2,166	$2,214	$2,206	$2,214	$2,424	$2,600
Less: Cash, Cash Equivalents, and Restricted Cash	6	13	55	-	21	4	22	156
Net Debt	$2,361	$2,408	$2,111	$2,214	$2,185	$2,210	$2,402	$2,444
Includes current portion
(Dollars in millions)
Adjusted Net Debt	31-Mar-26	31-Dec-25	31-Dec-24	31-Dec-23	31-Dec-22	31-Dec-21	31-Dec-20	30-Sep-20
Total Long-Term Debt (GAAP)	$2,367	$2,421	$2,166	$2,214	$2,206	$2,214	$2,424	$2,600
Plus: Impact of Recent Accounting Pronouncement	-	-	-	-	-	82	98	101
Less: Cash, Cash Equivalents, and Restricted Cash	6	13	55	-	21	4	22	156
Adjusted Net Debt	$2,361	$2,408	$2,111	$2,214	$2,185	$2,292	$2,500	$2,545
Includes current portion
On January 1, 2022, the Company adopted Accounting Standards Update (ASU) 2020-06 - Accounting for Convertible Instruments and Contracts in an Entity's Own Equity and upon adoption long-term debt increased by $82MM (See Note 12 - Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of CNX’s December 31, 2022 Form 10-K for additional information). As this adjustment was recorded on a prospective basis, Management believes that presenting investors with the net debt on a historical basis would be beneficial.

	Three Months Ended				Twelve Months Ended
Adjusted TTM EBITDAX: EBITDAX over the trailing-twelve-months after adjusting for the discrete items listed below.
(Dollars in millions)	30-Jun-25	30-Sep-25	31-Dec-25	31-Mar-26	31-Mar-26
Net Income	$433	$202	$196	$348	$1,179
Interest Expense	43	43	42	41	169
Interest Income	(1)	-	-	-	(1)
Income Tax Expense	153	64	28	80	325
Earnings Before Interest & Taxes (EBIT)	628	309	266	469	1,672
Depreciation, Depletion & Amortization	153	149	145	135	582
Exploration Expense	2	2	5	4	13
Earnings Before Interest, Taxes, DD&A, and Exploration (EBITDAX)	783	460	416	608	2,267
Adjustments:
Unrealized Gain on Commodity Derivative Instruments	(456)	(110)	(130)	(226)	(922)
Gain on Non-Core Asset Sale	-	(57)	-	-	(57)
Stock Based Compensation	5	5	5	6	21
Loss on Debt Extinguishment	-	-	1	12	13
Total Pre-tax Adjustments	(451)	(162)	(124)	(208)	(945)
Adjusted EBITDAX TTM	$332	$298	$292	$400	$1,322

Non-GAAP Measures
The Company's management believes that the following measures provide useful information to external users of the Company's consolidated financial statements, such as industry analysts, lenders and ratings agencies. Free cash flow should not be considered as alternatives to net cash provided by operating activities or any other measure of liquidity presented in accordance with GAAP.
Free Cash Flow (FCF): Net cash provided by operating activities minus capital expenditures plus proceeds from asset sales and minus investments in equity affiliates.
2026 Free Cash Flow
(Dollars in millions)	Q1-2026
Net Cash Provided by Operating Activities	$278
Capital Expenditures	(170)
Proceeds from Asset Sales	32
Investments in Equity Affiliates	(1)
Free Cash Flow	$139
2025 Free Cash Flow
(Dollars in millions)	Q4-2025	Q3-2025	Q2-2025	Q1-2025	YTD-2025
Net Cash Provided by Operating Activities	$296	$234	$283	$216	$1,029
Capital Expenditures	(174)	(76)	(114)	(131)	(495)
Proceeds from Asset Sales	3	68	21	16	108
Investments in Equity Affiliates	7	-	(2)	(1)	4
Free Cash Flow	$132	$226	$188	$100	$646
2024 Free Cash Flow
(Dollars in millions)	Q4-2024	Q3-2024	Q2-2024	Q1-2024	YTD-2024
Net Cash Provided by Operating Activities	$269	$170	$192	$185	$816
Capital Expenditures	(105)	(115)	(152)	(168)	(540)
Proceeds from Asset Sales	37	8	7	8	60
Investments in Equity Affiliates	(2)	(3)	-	-	(5)
Free Cash Flow	$199	$60	$47	$25	$331
2023 Free Cash Flow
(Dollars in millions)	Q4-2023	Q3-2023	Q2-2023	Q1-2023	YTD-2023
Net Cash Provided by Operating Activities	$161	$206	$199	$248	$814
Capital Expenditures	(107)	(206)	(196)	(170)	(679)
Proceeds from Asset Sales	8	19	132	11	170
Free Cash Flow	$62	$19	$135	$89	$305
2022 Free Cash Flow
(Dollars in millions)	Q4-2022	Q3-2022	Q2-2022	Q1-2022	YTD-2022
Net Cash Provided by Operating Activities	$442	$265	$192	$336	$1,235
Capital Expenditures	(173)	(134)	(137)	(122)	(566)
Proceeds from Asset Sales	7	4	7	20	38
Free Cash Flow	$276	$135	$62	$234	$707
2021 Free Cash Flow
(Dollars in millions)	Q4-2021	Q3-2021	Q2-2021	Q1-2021	YTD-2021
Net Cash Provided by Operating Activities	$254	$215	$239	$219	$927
Capital Expenditures	(117)	(97)	(129)	(123)	(466)
Proceeds from Asset Sales	21	12	7	5	45
Free Cash Flow	$158	$130	$117	$101	$506
2020 Free Cash Flow
(Dollars in millions)	Q4-2020	Q3-2020	Q2-2020	Q1-2020	YTD-2020
Net Cash Provided by Operating Activities	$161	$223	$144	$267	$795
Capital Expenditures	(92)	(108)	(135)	(152)	(487)
Proceeds from Asset Sales	16	6	12	14	48
Free Cash Flow	$85	$121	$21	$129	$356

Risk Factors

This presentation, including the oral statements made in connection herewith, contains forward-looking statements estimates and projections within the meaning of the federal securities laws. Statements that are not historical are forward-looking and may include our operational and strategic plans; estimates of gas reserves and resources; projected timing and rates of return of future investments; and projections and estimates of future production revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those statements estimates and projections. Investors should not place undue reliance on forward-looking statements as a prediction of future actual results. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly.

Forward-looking statements notice

Specific factors that could cause future actual results to differ materially from the forward-looking statements are described in detail under the captions “Cautionary Statement Regarding Forward-looking Statements” and “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 filed with the Securities and Exchange Commission (SEC) on February 10, 2026, as supplemented by our quarterly reports on Form 10-Q, and any other reports filed with the SEC. Those risk factors discuss, among other matters, pricing volatility or pricing decline for natural gas and NGLs; local, regional and national economic conditions and the impact they may have on our customers; events beyond our control, including a global or domestic health crisis or global instability; our operations and national and global economic conditions, generally; conditions in the oil and gas industry; the financial condition of our customers; any nonperformance by customers of their contractual obligations; changes in customer, employee or supplier relationships; ability to quality for environmental attribute credits and the volatility of environmental attribute markets; and changes in safety, health, environmental and other regulations.