News Release                    

Coterra Energy Reports Second-Quarter 2024 Results, Announces Quarterly Dividend, and Provides Third-Quarter 2024 Guidance and Full-Year 2024 Updates

HOUSTON, August 1, 2024 - Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported second-quarter 2024 financial and operating results and declared a quarterly dividend of $0.21 per share. Additionally, the Company provided third-quarter production and capital guidance and updated full-year 2024 guidance.

Key Takeaways & Updates

•For the second quarter of 2024, total barrels of oil equivalent (BOE) production, natural gas production, and oil production all beat the high-end of guidance, and incurred capital expenditures (non-GAAP) came in near the low-end of guidance.

•Increasing full-year 2024 BOE production guidance by 1% and oil production guidance by 2.4% from guidance provided in May, driven by faster cycle times and strong well performance. Maintaining full-year 2024 incurred capital expenditure (non-GAAP) guidance.

•For the second quarter of 2024, shareholder returns totaled 120% of Free Cash Flow (non-GAAP), inclusive of our declared quarterly base dividend and $140 million of share repurchases during the quarter (cash basis, excluding 1% excise tax). The Company remains committed to returning 50% or greater of its annual Free Cash Flow (non-GAAP) to shareholders and has returned 103% year to date.

•Simul-frac efficiencies are exceeding expectations on our Windham Row Development. To date, 21 of the planned wells in the row have come online an average of 4 days ahead of schedule. We now plan to add an additional 3 Harkey wells to the project, bringing total wells in the row to 57, and further improving the capital efficiency of the project. Furthermore, due to early success, we now plan to simul-frac 45 of the 57 wells in the row.

Tom Jorden, Chairman, CEO and President of Coterra, noted, "Coterra's second quarter results continue the trend of delivering outstanding performance. The ingenuity and hard work of our operating team are driving results that exceed expectations across our portfolio of high-quality assets. As we move into the second half of 2024, we remain focused on executing our plan while maintaining significant investment optionality between oil and gas in 2025. Coterra's investment thesis remains strong. Operational excellence, efficient development of our diversified, low-cost, long-life assets, our fortress balance sheet, and an unwavering commitment to shareholder returns underpin our value proposition."

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Second-Quarter 2024 Highlights

•Net Income (GAAP) totaled $220 million, or $0.30 per share. Adjusted Net Income (non-GAAP) was $272 million, or $0.37 per share.

•Cash Flow From Operating Activities (GAAP) totaled $558 million. Discretionary Cash Flow (non-GAAP) totaled $725 million.

•Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $479 million. Incurred capital expenditures from drilling, completion and other fixed asset additions (non-GAAP) totaled $477 million, near the low end of our guidance range of $470 to $550 million.

•Free Cash Flow (non-GAAP) totaled $246 million.

•Unit operating cost (reflecting costs from direct operations, transportation, production taxes and G&A) totaled $8.35 per BOE, within our annual guidance range of $7.45 to $9.55 per BOE.

•Total equivalent production of 669 MBoepd (thousand barrels of oil equivalent per day), was above the high end of guidance (625 to 655 MBoepd), driven by improved cycle times and strong well performance in all three of our regions.

◦Oil production averaged 107.2 MBopd (thousand barrels of oil per day), slightly exceeding the high end of guidance (103 to 107 MBopd).

◦Natural gas production averaged 2,780 MMcfpd (million cubic feet per day), exceeding the high end of guidance (2,600 to 2,700 MMcfpd) as Marcellus base production outperformed expectations.

◦NGLs production averaged 98.8 MBoepd.

•Realized average prices:

◦Oil was $79.37 per Bbl (barrel), excluding the effect of commodity derivatives, and $79.39 per Bbl, including the effect of commodity derivatives.

◦Natural Gas was $1.26 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $1.40 per Mcf, including the effect of commodity derivatives.

◦NGLs were $19.53 per Bbl.

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Shareholder Return Highlights

•Common Dividend: On August 1, 2024, Coterra's Board of Directors (the "Board") approved a quarterly base dividend of $0.21 per share, equating to a 3.3% annualized yield, based on the Company's $25.80 closing share price on July 31, 2024. The dividend will be paid on August 29, 2024 to holders of record on August 15, 2024.

•Share Repurchases: During the quarter, the Company repurchased 5.0 million shares for $140 million (cash basis, excluding 1% excise tax) at a weighted-average price of approximately $27.72 per share, leaving $1.3 billion remaining as of June 30, 2024 on its $2.0 billion share repurchase authorization.

•Total Shareholder Return: During the quarter, total shareholder returns amounted to $295 million, comprised of $155 million of declared dividends and $140 million of share repurchases (cash basis, excluding 1% excise tax).

•Reiterate Shareholder Return Strategy: Coterra is committed to returning 50% or greater of annual Free Cash Flow (non-GAAP) to shareholders through its $0.84 per share annual dividend and share repurchases. Year to date, Coterra has returned 103% of Free Cash Flow (non-GAAP) to shareholders.

Guidance Updates:

•Reiterated 2024 incurred capital expenditures (non-GAAP) of $1.75 to $1.95 billion.

•Increased 2024 oil production guidance to 105.5 to 108.5 MBopd, up 2.4% at the mid-point versus prior guidance.

•Maintained 2024 natural gas production guidance at the mid-point, tightened range to 2,675 to 2,775 MMcfpd.

•Increased 2024 BOE production guidance to 645 to 675, up 1% at the mid-point versus prior guidance.

•Announced third-quarter 2024 total equivalent production of 620 to 650 MBoepd, oil production of 107.0 to 111.0 MBopd, natural gas production of 2,500 to 2,630 MMcfpd, and incurred capital expenditures (non-GAAP) of $450 to $530 million.

•Estimate 2024 Discretionary Cash Flow (non-GAAP) of approximately $3.2 billion and 2024 Free Cash Flow (non-GAAP) of approximately $1.3 billion, at $80/bbl WTI and $2.37/mmbtu annual average NYMEX assumptions.

•For more details on annual and third quarter 2024 guidance, see 2024 Guidance Section in the tables below.

Strong Financial Position

As of June 30, 2024, Coterra had total debt outstanding of $2.646 billion, of which $575 million is due in September 2024. Coterra expects to retire its September 2024 maturity with cash on hand. The Company exited the quarter with cash and cash equivalents of $1.07 billion, $250 million in short-term investments, and no debt outstanding under its $1.5 billion revolving credit facility, resulting in total liquidity of approximately $2.82 billion. Coterra's net debt to trailing twelve-month EBITDAX ratio (non-GAAP) at June 30, 2024 was 0.4x.

See “Supplemental non-GAAP Financial Measures” below for descriptions of the above non-GAAP measures as well as reconciliations of these measures to the associated GAAP measures.

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Committed to Sustainability and ESG Leadership

Coterra is committed to environmental stewardship, sustainable practices, and strong corporate governance. The Company's sustainability report can be found under "ESG" on www.coterra.com. Coterra published its 2024 Sustainability report on August 1, 2024.

Second-Quarter 2024 Conference Call

Coterra will host a conference call tomorrow, Friday, August 2, 2024, at 8:00 AM CT (9:00 AM ET), to discuss second-quarter 2024 financial and operating results.

Conference Call Information

Date: August 2, 2024

Time: 8:00 AM CT / 9:00 AM ET

Dial-in (for callers in the U.S. and Canada): (800) 715-9871

International dial-in: +1 (646) 307-1963

Conference ID: 8017228

The live audio webcast and related earnings presentation can be accessed on the "Events & Presentations" page under the "Investors" section of the Company's website at www.coterra.com. The webcast will be archived and available at the same location after the conclusion of the live event.

About Coterra Energy

Coterra is a premier exploration and production company based in Houston, Texas with operations focused in the Permian Basin, Marcellus Shale, and Anadarko Basin. We strive to be a leading energy producer, delivering sustainable returns through the efficient and responsible development of our diversified asset base. Learn more about us at www.coterra.com.

Cautionary Statement Regarding Forward-Looking Information

This press release contains certain forward-looking statements within the meaning of federal securities laws. Forward-looking statements are not statements of historical fact and reflect Coterra's current views about future events. Such forward-looking statements include, but are not limited to, statements about returns to shareholders, enhanced shareholder value, reserves estimates, future financial and operating performance, and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals, including with respect to the publication of Coterra’s Sustainability Report, and other statements that are not historical facts contained in this press release. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "predict," "potential," "possible," "may," "should," "could," "would," "will," "strategy," "outlook", "guide" and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this press

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release will occur as projected and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the volatility in commodity prices for crude oil and natural gas; cost increases; the effect of future regulatory or legislative actions; the impact of public health crises, including pandemics and epidemics and any related company or governmental policies or actions, financial condition and results of operations; actions by, or disputes among or between, the Organization of Petroleum Exporting Countries and other producer countries; market factors; market prices (including geographic basis differentials) of oil and natural gas; impacts of inflation; labor shortages and economic disruption, (geopolitical disruptions such as the war in Ukraine or conflict in the Middle East or further escalation thereof); determination of reserves estimates, adjustments or revisions, including factors impacting such determination such as commodity prices, well performance, operating expenses and completion of Coterra’s annual PUD reserves process, as well as the impact on our financial statements resulting therefrom; the presence or recoverability of estimated reserves; the ability to replace reserves; environmental risks; drilling and operating risks; exploration and development risks; competition; the ability of management to execute its plans to meet its goals; and other risks inherent in Coterra's businesses. In addition, the declaration and payment of any future dividends, whether regular base quarterly dividends, variable dividends or special dividends, will depend on Coterra's financial results, cash requirements, future prospects and other factors deemed relevant by Coterra's Board. While the list of factors presented here is considered representative, no such list should be considered to be a complete statement of all potential risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. For additional information about other factors that could cause actual results to differ materially from those described in the forward-looking statements, please refer to Coterra's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other filings with the SEC, which are available on Coterra's website at www.coterra.com.

Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Except to the extent required by applicable law, Coterra does not undertake any obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof.

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Operational Data

The tables below provide a summary of production volumes, price realizations and operational activity by region and units costs for the Company for the periods indicated:

	Quarter Ended  June 30,				Six Months Ended  June 30,
	2024		2023		2024		2023
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)	2,114.4		2,322.8		2,212.6		2,229.1
Daily equivalent production (MBoepd)	352.4		387.1		368.8		371.5
Permian Basin
Natural gas (Mmcf/day)	484.5		406.7		485.6		416.9
Oil (MBbl/day)	99.6		89.7		98.3		87.0
NGL (MBbl/day)	78.1		65.4		74.1		64.7
Daily equivalent production (MBoepd)	258.4		222.9		253.3		221.2
Anadarko Basin
Natural gas (Mmcf/day)	179.4		173.9		170.3		184.1
Oil (MBbl/day)	7.5		6.1		6.5		7.0
NGL (MBbl/day)	20.6		19.6		20.3		19.4
Daily equivalent production (MBoepd)	58.0		54.7		55.2		57.1
Total Company
Natural gas (Mmcf/day)	2,779.8		2,904.4		2,869.9		2,830.9
Oil (MBbl/day)	107.2		95.8		104.9		94.0
NGL (MBbl/day)	98.8		85.0		94.5		84.2
Daily equivalent production (MBoepd)	669.2		664.9		677.7		650.1
AVERAGE SALES PRICE (excluding hedges)
Marcellus Shale
Natural gas ($/Mcf)	$	1.66	$	1.78	$	1.94	$	2.70
Permian Basin
Natural gas ($/Mcf)	$	(0.53)	$	0.92	$	0.25	$	1.16
Oil ($/Bbl)	$	79.37	$	71.71	$	77.30	$	72.80
NGL ($/Bbl)	$	18.95	$	15.36	$	19.70	$	18.85
Anadarko Basin
Natural gas ($/Mcf)	$	1.35	$	1.57	$	1.70	$	2.40
Oil ($/Bbl)	$	79.40	$	74.32	$	77.45	$	74.56
NGL ($/Bbl)	$	21.75	$	21.02	$	22.39	$	24.27
Total Company
Natural gas ($/Mcf)	$	1.26	$	1.65	$	1.64	$	2.46
Oil ($/Bbl)	$	79.37	$	71.88	$	77.31	$	72.93
NGL ($/Bbl)	$	19.53	$	16.67	$	20.28	$	20.11

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	Quarter Ended  June 30,				Six Months Ended  June 30,
	2024		2023		2024		2023
AVERAGE SALES PRICE (including hedges)
Total Company
Natural gas ($/Mcf)	$	1.40	$	1.95	$	1.76	$	2.81
Oil ($/Bbl)	$	79.39	$	72.17	$	77.25	$	73.11
NGL ($/Bbl)	$	19.53	$	16.67	$	20.28	$	20.11

	Quarter Ended  June 30,		Six Months Ended  June 30,
	2024	2023	2024	2023
WELLS DRILLED(1)
Gross wells
Marcellus Shale	8	16	22	36
Permian Basin	63	33	111	72
Anadarko Basin	11	11	19	17
	82	60	152	125
Net wells
Marcellus Shale	8.0	16.0	21.0	36.0
Permian Basin	26.8	21.3	50.0	37.9
Anadarko Basin	7.0	5.1	13.7	8.4
	41.8	42.4	84.7	82.3
TURN IN LINES
Gross wells (2)
Marcellus Shale	12	20	23	45
Permian Basin	56	34	98	79
Anadarko Basin	26	3	31	7
	94	57	152	131
Net wells (2)
Marcellus Shale	12.0	20.0	23.0	45.0
Permian Basin	22.6	19.1	44.5	42.2
Anadarko Basin	15.2	—	15.3	0.1
	49.8	39.1	82.8	87.3
AVERAGE RIG COUNTS
Marcellus Shale	1.2	3.0	1.6	3.0
Permian Basin	8.0	6.0	8.0	6.0
Anadarko Basin	1.3	2.0	1.7	1.5

_______________________________________________________________________________

(1)Wells drilled represents wells drilled to total depth during the period.

(2)The 12 turn-in lines in the Marcellus Shale were brought online for less than 10 days on average in order to de-water the developments. These wells were subsequently shut-in or heavily curtailed and contributed negligible volumes during the quarter (a total of 18 MMcf/d, or less than 0.1% of total company gas volumes during the quarter). The wells were returned online in early July.

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	Quarter Ended  June 30,				Six Months Ended  June 30,
	2024		2023		2024		2023
AVERAGE UNIT COSTS ($/Boe) (1)
Direct operations	$	2.62	$	2.16	$	2.56	$	2.24
Gathering, processing and transportation	3.99		4.27		3.99		4.20
Taxes other than income	0.89		1.05		1.04		1.27
General and administrative (excluding stock-based compensation and severance expense)	0.85		0.79		0.92		0.85
Unit Operating Cost	$	8.35	$	8.27	$	8.52	$	8.56
Depreciation, depletion and amortization	7.34		6.54		7.12		6.50
Exploration	0.09		0.09		0.08		0.08
Stock-based compensation	0.26		0.11		0.24		0.19
Severance expense	—		0.05		—		0.09
Interest expense, net	0.23		0.09		0.15		0.09
	$	16.26	$	15.15	$	16.10	$	15.51

_______________________________________________________________________________

(1)Total unit costs may differ from the sum of the individual costs due to rounding.

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Derivatives Information

As of June 30, 2024, the Company had the following outstanding financial commodity derivatives:

	2024
Natural Gas	Third Quarter		Fourth Quarter
NYMEX collars
Volume (MMBtu)	45,080,000		28,890,000
Weighted average floor ($/MMBtu)	$	2.75	$	2.75
Weighted average ceiling ($/MMBtu)	$	3.94	$	4.68

	2025
Natural Gas	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
NYMEX collars
Volume (MMBtu)	27,000,000		27,300,000		27,600,000		27,600,000
Weighted average floor ($/MMBtu)	$	2.92	$	2.92	$	2.92	$	2.92
Weighted average ceiling ($/MMBtu)	$	5.12	$	4.37	$	4.37	$	6.20

	2026
Natural Gas	First Quarter
NYMEX collars
Volume (MMBtu)	18,000,000
Weighted average floor ($/MMBtu)	$	2.75
Weighted average ceiling ($/MMBtu)	$	8.30

	2024				2025
Oil	Third Quarter		Fourth Quarter		First Quarter		Second Quarter
WTI oil collars
Volume (MBbl)	3,220		3,220		1,800		1,820
Weighted average floor ($/Bbl)	$	65.00	$	65.00	$	62.50	$	62.50
Weighted average ceiling ($/Bbl)	$	87.01	$	87.01	$	81.67	$	81.67
WTI Midland oil basis swaps
Volume (MBbl)	4,600		4,600		1,800		1,820
Weighted average differential ($/Bbl)	$	1.13	$	1.13	$	1.24	$	1.24

In July 2024, the Company entered into the following financial commodity derivatives:

	2025
Oil	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
WTI oil collars
Volume (MBbl)	900		910		1,380		1,380
Weighted average floor ($/Bbl)	$	65.00	$	65.00	$	65.00	$	65.00
Weighted average ceiling ($/Bbl)	$	84.07	$	84.07	$	83.18	$	83.18
WTI Midland oil basis swaps
Volume (MBbl)	900		910		1,380		1,380
Weighted average differential ($/Bbl)	$	1.13	$	1.13	$	1.14	$	1.14

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CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

	Quarter Ended June 30,				Six Months Ended  June 30,
(In millions, except per share amounts)	2024		2023		2024		2023
OPERATING REVENUES
Oil	$	774	$	626	$	1,475	$	1,241
Natural gas	319		436		857		1,258
NGL	176		129		349		306
Gain (loss) on derivative instruments	(16)		(12)		(16)		126
Other	18		6		39		31
	1,271		1,185		2,704		2,962
OPERATING EXPENSES
Direct operations	160		130		316		264
Gathering, processing and transportation	242		258		492		494
Taxes other than income	54		63		128		149
Exploration	5		5		10		9
Depreciation, depletion and amortization	447		395		879		764
General and administrative (excluding stock-based compensation and severance expense)	52		48		114		100
Stock-based compensation	16		7		29		23
Severance expense	—		3		—		11
	976		909		1,968		1,814
Gain on sale of assets	1		—		—		5
INCOME FROM OPERATIONS	296		276		736		1,153
Interest expense	34		16		53		33
Interest income	(19)		(10)		(35)		(22)
Income before income taxes	281		270		718		1,142
Income tax expense	61		61		146		256
NET INCOME	$	220	$	209	$	572	$	886
Earnings per share - Basic	$	0.30	$	0.28	$	0.77	$	1.16
Weighted-average common shares outstanding	742		755		746		760

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CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

(In millions)	June 30, 2024		December 31, 2023
ASSETS
Cash and cash equivalents	$	1,070	$	956
Short-term investments	250		—
Other current assets	1,017		1,059
Properties and equipment, net (successful efforts method)	17,996		17,933
Other assets	431		467
	$	20,764	$	20,415
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities	$	1,090	$	1,085
Current portion of long-term debt	575		575
Long-term debt, net (excluding current maturities)	2,071		1,586
Deferred income taxes	3,390		3,413
Other long term liabilities	601		709
Cimarex redeemable preferred stock	8		8
Stockholders’ equity	13,029		13,039
	$	20,764	$	20,415

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CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

	Quarter Ended June 30,				Six Months Ended  June 30,
(In millions)	2024		2023		2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	220	$	209	$	572	$	886
Depreciation, depletion and amortization	447		395		879		764
Deferred income tax (benefit) expense	(1)		4		(23)		27
Gain on sale of assets	(1)		—		—		(5)
(Gain) loss on derivative instruments	16		12		16		(126)
Net cash received in settlement of derivative instruments	36		84		62		184
Stock-based compensation and other	13		7		25		24
Income charges not requiring cash	(5)		(6)		(9)		(10)
Changes in assets and liabilities	(167)		(59)		(108)		396
Net cash provided by operating activities	558		646		1,414		2,140
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions	(479)		(592)		(936)		(1,075)
Capital expenditures for leasehold and property acquisitions	(2)		(5)		(3)		(6)
Purchases of short-term investments	—		—		(250)		—
Proceeds from sale of assets	1		28		1		33
Net cash used in investing activities	(480)		(569)		(1,188)		(1,048)
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from debt	—		—		499		—
Repayment of finance leases	(2)		(1)		(3)		(3)
Common stock repurchases	(140)		(57)		(290)		(325)
Dividends paid	(156)		(152)		(314)		(588)
Tax withholding on vesting of stock awards	—		—		—		(1)
Capitalized debt issuance costs	—		—		(5)		(7)
Cash paid for conversion of redeemable preferred stock	—		—		—		(1)
Cash received for stock option exercises	1		—		1		—
Net cash used in financing activities	(297)		(210)		(112)		(925)
Net increase (decrease) in cash, cash equivalents and restricted cash	$	(219)	$	(133)	$	114	$	167

Reconciliation of Incurred Capital Expenditures

Incurred capital expenditures is defined as capital expenditures for drilling, completion and other fixed asset additions less changes in accrued capital costs.

	Quarter Ended June 30,				Six Months Ended  June 30,
(In millions)	2024		2023		2024		2023
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP)	$	479	$	592	$	936	$	1,075
Change in accrued capital costs	(2)		(55)		(9)		30
Incurred capital expenditures for drilling, completion and other fixed asset additions (non-GAAP)	$	477	537		$	927	$	1,105

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Supplemental Non-GAAP Financial Measures (Unaudited)

We report our financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, we believe certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results and results of prior periods. In addition, we believe these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations below that compare GAAP financial measures to non-GAAP financial measures for the periods indicated.

We have also included herein certain forward-looking non-GAAP financial measures. Due to the forward-looking nature of these non-GAAP financial measures, we cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as changes in assets and liabilities (including future impairments) and cash paid for certain capital expenditures. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant.

Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings Per Share

Adjusted Net Income and Adjusted Earnings per Share are presented based on our management's belief that these non-GAAP measures enable a user of financial information to understand the impact of identified adjustments on reported results. Adjusted Net Income is defined as net income plus gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, severance expense, and tax effect on selected items. Adjusted Earnings per Share is defined as Adjusted Net Income divided by weighted-average common shares outstanding. Additionally, we believe these measures provide beneficial comparisons to similarly adjusted measurements of prior periods and use these measures for that purpose. Adjusted Net Income and Adjusted Earnings per Share are not measures of financial performance under GAAP and should not be considered as alternatives to net income and earnings per share, as defined by GAAP.

	Quarter Ended June 30,				Six Months Ended  June 30,
(In millions, except per share amounts)	2024		2023		2024		2023
As reported - net income	$	220	$	209	$	572	$	886
Reversal of selected items:
Gain on sale of assets	(1)		—		—		(5)
(Gain) loss on derivative instruments(1)	52		96		78		58
Stock-based compensation expense	16		7		29		23
Severance expense	—		3		—		11
Tax effect on selected items	(15)		(24)		(24)		(20)
Adjusted net income	$	272	$	291	$	655	$	953
As reported - earnings per share	$	0.30	$	0.28	$	0.77	$	1.16
Per share impact of selected items	0.07		0.11		0.11		0.09
Adjusted earnings per share	$	0.37	$	0.39	$	0.88	$	1.25
Weighted-average common shares outstanding	742		755		746		760

_______________________________________________________________________________

(1)This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in Gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

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Reconciliation of Discretionary Cash Flow and Free Cash Flow

Discretionary Cash Flow is defined as cash flow from operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate available cash to internally fund exploration and development activities, return capital to shareholders through dividends and share repurchases, and service debt and is used by our management for that purpose. Discretionary Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

Free Cash Flow is defined as Discretionary Cash Flow less cash paid for capital expenditures. Free Cash Flow is an indicator of a company’s ability to generate cash flow after spending the money required to maintain or expand its asset base, and is used by our management for that purpose. Free Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

	Quarter Ended June 30,				Six Months Ended  June 30,
(In millions)	2024		2023		2024		2023
Cash flow from operating activities	$	558	$	646	$	1,414	$	2,140
Changes in assets and liabilities	167		59		108		(396)
Discretionary cash flow	725		705		1,522		1,744
Cash paid for capital expenditures for drilling, completion and other fixed asset additions	(479)		(592)		(936)		(1,075)
Free cash flow	$	246	$	113	$	586	$	669

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Reconciliation of Adjusted EBITDAX

Adjusted EBITDAX is defined as net income plus interest expense, interest income, income tax expense, depreciation, depletion, and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, and severance expense. Adjusted EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. Our management uses Adjusted EBITDAX for that purpose. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

	Quarter Ended June 30,				Six Months Ended  June 30,
(In millions)	2024		2023		2024		2023
Net income	$	220	$	209	$	572	$	886
Plus (less):
Interest expense	34		16		53		33
Interest income	(19)		(10)		(35)		(22)
Income tax expense	61		61		146		256
Depreciation, depletion and amortization	447		395		879		764
Exploration	5		5		10		9
Gain on sale of assets	(1)		—		—		(5)
Non-cash loss on derivative instruments	52		96		78		58
Severance expense	—		3		—		11
Stock-based compensation	16		7		29		23
Adjusted EBITDAX	$	815	$	782	$	1,732	$	2,013

	Trailing Twelve Months Ended
(In millions)	June 30, 2024		December 31, 2023
Net income	$	1,311	$	1,625
Plus (less):
Interest expense	93		73
Interest income	(60)		(47)
Income tax expense	393		503
Depreciation, depletion and amortization	1,756		1,641
Exploration	21		20
Gain on sale of assets	(7)		(12)
Non-cash loss on derivative instruments	75		54
Severance expense	1		12
Stock-based compensation	65		59
Adjusted EBITDAX (trailing twelve months)	$	3,648	$	3,928

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Reconciliation of Net Debt

The total debt to total capitalization ratio is calculated by dividing total debt by the sum of total debt and total stockholders’ equity. This ratio is a measurement which is presented in our annual and interim filings and our management believes this ratio is useful to investors in assessing our leverage. Net Debt is calculated by subtracting cash and cash equivalents and short-term investments from total debt. The Net Debt to Adjusted Capitalization ratio is calculated by dividing Net Debt by the sum of Net Debt and total stockholders’ equity. Net Debt and the Net Debt to Adjusted Capitalization ratio are non-GAAP measures which our management believes are also useful to investors when assessing our leverage since we have the ability to and may decide to use a portion of our cash and cash equivalents and short-term investments to retire debt. Our management uses these measures for that purpose. Additionally, as our planned expenditures are not expected to result in additional debt, our management believes it is appropriate to apply cash and cash equivalents and short-term investments to reduce debt in calculating the Net Debt to Adjusted Capitalization ratio.

(In millions)	June 30, 2024			December 31, 2023
Current portion of long-term debt	$	575		$	575
Long-term debt, net	2,071			1,586
Total debt	2,646			2,161
Stockholders’ equity	13,029			13,039
Total capitalization	$	15,675		$	15,200
Total debt	$	2,646		$	2,161
Less: Cash and cash equivalents	(1,070)			(956)
Less: Short-term investments	(250)			—
Net debt	$	1,326		$	1,205
Net debt	$	1,326		$	1,205
Stockholders’ equity	13,029			13,039
Total adjusted capitalization	$	14,355		$	14,244
Total debt to total capitalization ratio	16.9		%	14.2		%
Less: Impact of cash and cash equivalents	7.7		%	5.7		%
Net debt to adjusted capitalization ratio	9.2		%	8.5		%

Reconciliation of Net Debt to Adjusted EBITDAX

Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted EBITDAX is defined as net debt divided by trailing twelve month Adjusted EBITDAX. Net debt to Adjusted EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage.

(In millions)	June 30, 2024			December 31, 2023
Total debt	$	2,646		$	2,161
Net income	1,311			1,625
Total debt to net income ratio	2.0		x	1.3		x
Net debt (as defined above)	$	1,326		$	1,205
Adjusted EBITDAX (Trailing twelve months)	3,648			3,928
Net debt to Adjusted EBITDAX	0.4		x	0.3		x

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2024 Guidance

The tables below present full-year and second quarter 2024 guidance.

	Full Year Guidance
	2024 Guidance (May)	Updated 2024 Guidance
	Low Mid High	Low Mid High
Total Equivalent Production (MBoed)	635 - 655 - 675	645 - 660 - 675
Gas (Mmcf/day)	2,650 - 2,725 - 2,800	2,675 - 2,725 - 2,775
Oil (MBbl/day)	102.0 - 104.5 - 107.0	105.5 - 107.0 - 108.5
Net wells turned in line
Marcellus Shale	37 - 40 - 43	No change
Permian Basin	75 - 83 - 90	80 - 85 - 90
Anadarko Basin	20 - 23 - 25	21 - 24 - 27
Incurred capital expenditures ($ in millions)
Total Company	$1,750 - $1,850 - $1,950	No change
Drilling and completion
Marcellus Shale	$350- $375 -$400	$375 midpoint
Permian Basin	$945 - $1,000 - $1,055	$1,000 midpoint
Anadarko Basin	$270 - $290 - $320	$290 midpoint
Midstream, saltwater disposal and infrastructure	$185 - $185 - $185	$185 midpoint
Commodity price assumptions:
WTI ($ per bbl)	$79	$80
Henry Hub ($ per mmbtu)	$2.35	$2.37
Cash Flow & Investment ($ in billions)
Discretionary Cash Flow	$3.1	$3.2
Incurred Capital Expenditures	$1.75 - $1.85 - $1.95	No change
Free Cash Flow (DCF - cash capex)	$1.3	$1.3
$ per boe, unless noted:
Lease operating expense + workovers + region office	$2.15 - $2.50 - $2.85	No change
Gathering, processing, & transportation	$3.50 - $4.00 - $4.50	No change
Taxes other than income	$1.00 - $1.10 - $1.20	No change
General & administrative (1)	$0.80 - $0.90 - $1.00	No change
Unit Operating Cost	$7.45 - $8.50 - $9.55	No change

_______________________________________________________________________________

(1)Excludes stock-based compensation and severance expense

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	Quarterly Guidance
	Second Quarter 2024 Guidance	Second Quarter 2024 Actual	Third Quarter 2024 Guidance
	Low Mid High		Low Mid High
Total Equivalent Production (MBoed)	625 - 640 - 655	669	620 - 635 - 650
Gas (Mmcf/day)	2,600 - 2,650 - 2,700	2,780	2,500 - 2,565 - 2,630
Oil (MBbl/day)	103.0 - 105.0 - 107.0	107.2	107.0 - 109.0 - 111.0
Net wells turned in line
Marcellus Shale	0 - 0 - 0	12	0 - 4 - 7
Permian Basin	15 - 23 - 30	23	15 - 20 - 25
Anadarko Basin	7-10-13	15	5
Incurred capital expenditures ($ in millions)
Total Company	$470 - $510 - $550	$477	$450 - $480 - $530

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Investor Contact

Daniel Guffey - Vice President of Finance, IR & Treasury

281.589.4875

Hannah Stuckey - Investor Relations Manager

281.589.4983

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