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Guidance history, every release

Coterra Energy (CTRA) · 8 releases, May 2, 2024 to Feb 26, 2026 · rows are metrics, columns are releases

Raised · a change from the previous releaseSame · restated unchanged— · not stated in that releaseEvery value links to its sentence in the filing

Metric	May 2, 2024 FY24 Q1	Aug 1, 2024 FY24 Q2	Oct 31, 2024 FY24 Q3	Feb 24, 2025 FY24 Q4	May 5, 2025 FY25 Q1	Aug 4, 2025 FY25 Q2	Nov 3, 2025 FY25 Q3	Feb 26, 2026 FY25 Q4
For FY2028
New Permian Power Netback Gas Sale Volume	—	—	—	—	—	New“50 MMcf per day for a seven-year term”	—	—
For FY2027
LNG natural gas sales	—	—	New“200 MMcfpd”	—	—	—	—	—
Pre-tax Synergy Capture (Devon-Coterra Merger)	—	—	—	—	—	—	—	New“$1 billion per year on a run-rate basis”
For FY2026
Annual BOE growth	—	—	—	—	—	—	New“0-5%”	—
Annual oil growth	—	—	—	—	—	—	New“approximately 5%”	—
Capital expenditures	—	—	—	—	—	—	—	New“$2.25 billion, with a range of $2.175 to $2.325 billion”
Capital expenditures	—	—	—	—	—	—	New“modestly down from 2025”	—
Capital Expenditures	—	—	—	—	—	—	—	New“$2.25 billion, with a range of $2.175 to $2.325 billion”
Capital expenditures - Drilling and completion - Anadarko Basin ($ in millions)	—	—	—	—	—	—	—	New“$190”
Capital expenditures - Drilling and completion - Marcellus Shale ($ in millions)	—	—	—	—	—	—	—	New“$350”
Capital expenditures - Drilling and completion - Permian Basin ($ in millions)	—	—	—	—	—	—	—	New“$1,530”
Capital expenditures - Midstream, saltwater disposal, infrastructure, and other ($ in millions)	—	—	—	—	—	—	—	New“$180”
Capital expenditures Total Company ($ in millions)	—	—	—	—	—	—	—	New“$2,175 $2,250 $2,325”
Commodity price assumption - Henry Hub ($ per mmbtu)	—	—	—	—	—	—	—	New“$3.86”
Commodity price assumption - WTI ($ per bbl)	—	—	—	—	—	—	—	New“$64”
Discretionary Cash Flow ($ in billions)	—	—	—	—	—	—	—	New“$4.60”
Free Cash Flow ($ in billions)	—	—	—	—	—	—	—	New“$2.35”
Free Cash Flow (non-GAAP)	—	—	—	—	—	—	—	New“$2.35 billion”
Gas (Mmcf/day)	—	—	—	—	—	—	—	New“2,775 2,875 2,975”
Natural gas production	—	—	—	—	—	—	—	New“2,775 to 2,975 MMcfpd”
Net wells turned in line Anadarko Basin	—	—	—	—	—	—	—	New“12 15 18”
Net wells turned in line Marcellus Shale	—	—	—	—	—	—	—	New“32 36 40”
Net wells turned in line Permian Basin	—	—	—	—	—	—	—	New“130 140 150”
Oil (MBbl/day)	—	—	—	—	—	—	—	New“162 167 172”
Oil production	—	—	—	—	—	—	—	New“162 to 172 MBopd”
Quarterly Dividend	—	—	—	—	—	—	—	New“$0.22 per share”
Reinvestment rate	—	—	—	—	—	—	—	New“approximately 50%”
Reinvestment rate	—	—	—	—	—	—	New“at, or below, 50%”	—
Total Equivalent Production	—	—	—	—	—	—	—	New“750 to 810 MBoepd”
Total Equivalent Production (MBoed)	—	—	—	—	—	—	—	New“750 780 810”
For FY2025
1Q25 capital expenditures	—	—	—	New“$525 to $625 million”	—	—	—	—
1Q25 natural gas production	—	—	—	New“2,850 to 3,000 MMcfpd”	—	—	—	—
1Q25 oil production	—	—	—	New“134 to 144 MBopd”	—	—	—	—
1Q25 total equivalent production	—	—	—	New“710 to 750 MBoepd”	—	—	—	—
Anadarko Basin rigs and completion crews	—	—	—	New“1.5 drilling rigs and 0.5 completion crews”	—	—	—	—
Annual Free Cash Flow returned to shareholders	—	—	—	—	New“50% or greater”	—	—	—
Average Anadarko Basin rig/completion crew count	—	—	—	New“1.5 drilling rigs and 0.5 completion crews”	—	—	—	—
Average annual capital	—	—	—	New“$2.1 to $2.4 billion”	—	—	—	—
Average Marcellus rig/completion crew count	—	—	—	New“1 rig and 0.5 completion crews”	—	—	—	—
Average Permian Basin rig/completion crew count	—	—	—	New“approximately 11 drilling rigs and 3 completion crews”	—	—	—	—
Average reinvestment rate	—	—	—	New“below 50%”	—	—	—	—
Capital budget range	—	—	—	—	New“$2.0 to $2.3 billion”	—	—	—
Capital expenditures	—	—	—	—	New“$2.0 to $2.3 billion”	—	—	—
Capital expenditures	—	—	—	New“$525 to $625 million”	—	—	—	—
Capital expenditures	—	—	—	New“between $2.1 and $2.4 billion”	—	—	—	—
Capital expenditures - Total Company ($ in millions)	—	—	—	—	New“$575 — $613 — $650”	—	—	—
Capital Expenditures ($ in billions)	—	—	—	—	New“$2.0 — $2.2 — $2.3”	Changed“$2.1 — $2.2 — $2.3”	Changed“$2.3”	—
Capital expenditures (2025 Outlook section)	—	—	—	New“$2.1 to $2.4 billion, up 28% year-over-year at the mid-point”	—	—	—	—
Capital expenditures (non-GAAP)	—	—	—	—	—	New“approximately $2.3 billion”	Reiterated“around $2.3 billion”	—
Capital expenditures (non-GAAP)	—	—	—	—	—	New“$625 to $675 million”	Lowered“approximately $530 million”	—
Capital expenditures (non-GAAP)	—	—	—	—	—	—	New“approximately $530 million”	—
Capital expenditures (non-GAAP)	—	—	—	—	New“$575 to $650 million”	—	—	—
Capital Expenditures (non-GAAP)	—	—	—	—	—	New“$625 to $675 million”	—	—
Capital expenditures Total Company ($ in millions)	—	—	—	—	New“$2,000 — $2,150 — $2,300”	Changed“$2,100 — $2,200 — $2,300”	Changed“$2,310”	—
Capital expenditures Total Company ($ in millions)	—	—	—	—	—	—	New“$530”	—
Capital expenditures Total Company ($ in millions)	—	—	—	—	—	New“$625 — $650 — $675”	—	—
Cash taxes	—	—	—	—	—	—	New“no cash taxes during fourth-quarter 2025”	—
Commodity price assumption - Henry Hub ($ per mmbtu)	—	—	—	—	New“$3.70”	Lowered“$3.67”	—	—
Commodity price assumption - WTI ($ per bbl)	—	—	—	—	New“$63”	Raised“$66”	—	—
Current tax (% of effective tax rate)	—	—	—	—	—	New“40% to 60%”	—	—
Current Tax Percentage	—	—	—	—	—	New“40% to 60%”	—	—
Discretionary Cash Flow	—	—	—	New“approximately $5.0 billion”	—	—	—	—
Discretionary Cash Flow ($ in billions)	—	—	—	—	—	New“$4.4”	Lowered“$4.3”	—
Discretionary Cash Flow (non-GAAP)	—	—	—	—	New“approximately $4.3 billion”	—	—	—
Discretionary Cash Flow (non-GAAP) estimate	—	—	—	New“approximately $5.0 billion”	—	—	—	—
Drilling and completion - Anadarko Basin (midpoint)	—	—	—	—	—	New“$230”	—	—
Drilling and completion - Marcellus Shale (midpoint)	—	—	—	—	—	New“$350”	—	—
Drilling and completion - Permian Basin (midpoint)	—	—	—	—	—	New“$1,520”	—	—
Drilling and completion Anadarko Basin	—	—	—	—	—	—	New“$230”	—
Drilling and completion capex - Anadarko Basin - 2025	—	—	—	New“$230 midpoint”	—	—	—	—
Drilling and completion capex - Marcellus Shale - 2025	—	—	—	New“$250 midpoint”	—	—	—	—
Drilling and completion capex - Permian Basin - 2025	—	—	—	New“$1,570 midpoint”	—	—	—	—
Drilling and completion Marcellus Shale	—	—	—	—	New“$300 midpoint”	—	Raised“$320”	—
Drilling and completion Permian Basin	—	—	—	—	New“$1,450 midpoint”	—	Raised“$1,560”	—
Effective tax rate	—	—	—	—	—	New“22%”	Reiterated“22%”	—
Free Cash Flow	—	—	—	New“approximately $2.7 billion”	—	—	—	—
Free Cash Flow (DCF - incurred capex) ($ in billions)	—	—	—	—	New“$2.1”	Reiterated“$2.1”	Lowered“$2.0”	—
Free Cash Flow (non-GAAP)	—	—	—	—	—	New“$2.1 billion”	Lowered“approximately $2.0 billion”	—
Free Cash Flow (non-GAAP) estimate	—	—	—	New“approximately $2.7 billion”	—	—	—	—
Gas (Mmcf/day)	—	—	—	—	New“2,725 — 2,800 — 2,875”	Changed“2,875 — 2,913 — 2,950”	Changed“2,925 — 2,945 — 2,965”	—
Gas (Mmcf/day)	—	—	—	—	—	—	New“2,775 — 2,850 — 2,925”	—
Gas (Mmcf/day)	—	—	—	—	—	New“2,750 — 2,825 — 2,900”	—	—
Gas (Mmcf/day)	—	—	—	—	New“2,700 — 2,775 — 2,850”	—	—	—
Gas (Mmcf/day) - 2025 (Low/Mid/High)	—	—	—	New“2,675 2,775 2,875”	—	—	—	—
Gas (Mmcf/day) - Q1 2025 (Low/Mid/High)	—	—	—	New“2,850 2,925 3,000”	—	—	—	—
Gathering, processing, & transportation ($/boe)	—	—	—	—	New“$3.25 — $3.75 — $4.25”	—	Reiterated“$3.25 — $3.75 — $4.25”	—
General & administrative ($/boe)	—	—	—	—	New“$0.90 — $1.00 — $1.10”	—	Reiterated“$0.90 — $1.00 — $1.10”	—
Henry Hub ($ per mmbtu)	—	—	—	—	—	—	New“No change”	—
Incremental Marcellus capital (option to keep second rig through year-end)	—	—	—	—	New“$50 million”	—	—	—
Incurred capital expenditures - Total Company - 2025 (Low/Mid/High)	—	—	—	New“$2,100 $2,250 $2,400”	—	—	—	—
Incurred capital expenditures - Total Company - Q1 2025 (Low/Mid/High)	—	—	—	New“$525 $575 $625”	—	—	—	—
Lease operating expense + workovers + region office ($/boe)	—	—	—	—	New“$2.50 — $3.05 — $3.60”	—	Reiterated“$2.50 — $3.05 — $3.60”	—
Marcellus rigs and completion crews	—	—	—	New“1 rig and 0.5 completion crews”	—	—	—	—
Midstream, saltwater disposal and infrastructure	—	—	—	—	New“$170 midpoint”	—	Raised“$200”	—
Midstream, saltwater disposal and infrastructure (midpoint)	—	—	—	—	—	New“$200”	—	—
Midstream, saltwater disposal and infrastructure capex - 2025	—	—	—	New“$200 midpoint”	—	—	—	—
Natural gas production	—	—	—	—	New“2,700 to 2,850 MMcfpd”	Raised“2,750 to 2,900 MMcfpd”	Raised“2,775 to 2,925 MMcfpd”	—
Natural gas production	—	—	—	—	—	—	New“2,925 to 2,965 MMcfpd”	—
Natural gas production	—	—	—	—	—	—	New“2,775 to 2,925 MMcfpd”	—
Natural gas production	—	—	—	—	New“2,700 to 2,850 MMcfpd”	—	—	—
Natural gas production	—	—	—	New“2,850 to 3,000 MMcfpd”	—	—	—	—
Natural gas production	—	—	—	New“2,675 to 2,875 MMcfpd”	—	—	—	—
Natural Gas Production	—	—	—	—	—	New“2,750 to 2,900 MMcfpd”	—	—
Natural gas volumes	—	—	—	New“relatively flat to 2024 levels”	—	—	—	—
Net wells turned in line - Anadarko Basin	—	—	—	—	New“9”	—	—	—
Net wells turned in line - Anadarko Basin - 2025 (Low/Mid/High)	—	—	—	New“15 20 25”	—	—	—	—
Net wells turned in line - Anadarko Basin - Q1 2025	—	—	—	New“0”	—	—	—	—
Net wells turned in line - Marcellus Shale	—	—	—	—	New“3”	—	—	—
Net wells turned in line - Permian Basin	—	—	—	—	New“45 — 55 — 65”	—	—	—
Net wells turned in line - Permian Basin - 2025 (Low/Mid/High)	—	—	—	New“150 158 165”	—	—	—	—
Net wells turned in line - Permian Basin - Q1 2025 (Low/Mid/High)	—	—	—	New“35 40 45”	—	—	—	—
Net wells turned in line Anadarko Basin	—	—	—	—	—	—	New“20”	—
Net wells turned in line Anadarko Basin	—	—	—	—	—	—	New“5”	—
Net wells turned in line Anadarko Basin	—	—	—	—	—	New“6”	—	—
Net wells turned in line Marcellus Shale	—	—	—	New“10 13 15”	—	—	Changed“9 — 13”	—
Net wells turned in line Marcellus Shale	—	—	—	—	—	—	New“2 — 6”	—
Net wells turned in line Marcellus Shale	—	—	—	—	—	New“4”	—	—
Net wells turned in line Permian Basin	—	—	—	—	—	—	New“165”	—
Net wells turned in line Permian Basin	—	—	—	—	—	—	New“41”	—
Net wells turned in line Permian Basin	—	—	—	—	—	New“40 — 45 — 50”	—	—
Oil (MBbl/day)	—	—	—	—	New“155 — 160 — 165”	Changed“157 — 160 — 163”	Changed“159 — 160 — 161”	—
Oil (MBbl/day)	—	—	—	—	—	—	New“172 — 175 — 178”	—
Oil (MBbl/day)	—	—	—	—	—	New“158 — 163 — 168”	—	—
Oil (MBbl/day)	—	—	—	—	New“147 — 152 — 157”	—	—	—
Oil (MBbl/day) - 2025 (Low/Mid/High)	—	—	—	New“152 160 168”	—	—	—	—
Oil (MBbl/day) - Q1 2025 (Low/Mid/High)	—	—	—	New“134 139 144”	—	—	—	—
Oil production	—	—	—	—	New“147 to 157 MBopd”	Raised“158 to 168 MBopd”	Raised“172 to 178 MBopd”	—
Oil production	—	—	—	—	—	—	New“159 to 161 MBopd”	—
Oil production	—	—	—	—	—	—	New“172 to 178 MBopd”	—
Oil production	—	—	—	—	New“147 to 157 MBopd”	—	—	—
Oil production	—	—	—	New“134 to 144 MBopd”	—	—	—	—
Oil production	—	—	—	New“152 to 168 MBopd”	—	—	—	—
Oil Production	—	—	—	—	—	New“158 to 168 MBopd”	—	—
Oil volumes growth	—	—	—	New“up approximately 47%”	—	—	—	—
Organic 2025 annual BOE growth (legacy assets, excluding recent acquisitions)	—	—	—	New“0 to 5%”	—	—	—	—
Organic 2025 annual oil growth (legacy assets, excluding recent acquisitions)	—	—	—	New“greater than 5%”	—	—	—	—
Per unit costs	—	—	—	—	—	—	New“expects fourth quarter per unit costs to trend closer to the mid-point of our annual guidance range”	—
Permian Basin rigs and completion crews	—	—	—	New“approximately 11 drilling rigs and 3 completion crews”	—	—	—	—
Permian capital reduction	—	—	—	—	New“approximately $150 million”	—	—	—
Permian rigs	—	—	—	—	New“seven”	—	—	—
Quarterly dividend	—	—	—	—	—	—	New“$0.22 per share”	—
Quarterly Dividend	—	—	—	—	—	New“$0.22 per share”	—	—
Reinvestment rate	—	—	—	—	—	—	New“approximately 55%”	—
Reinvestment rate (non-GAAP)	—	—	—	—	New“approximately 50%”	—	—	—
Reinvestment rate (non-GAAP)	—	—	—	New“slightly below 50%”	—	—	—	—
Second-half 2025 Permian rig count	—	—	—	—	New“seven Permian rigs”	—	—	—
Share repurchases	—	—	—	—	—	—	New“expects to continue to opportunistically repurchase its shares”	—
Taxes other than income ($/boe)	—	—	—	—	New“$1.25 — $1.50 — $1.75”	—	Reiterated“$1.25 — $1.50 — $1.75”	—
Term Loan Repayment Target	—	—	—	—	—	New“$650 million”	—	—
Term loan retirement	—	—	—	New“$1.0 billion”	—	—	—	—
Term loans	—	—	—	New“$1.0 billion”	Lowered“$750 million”	—	—	—
Three-year outlook annual average BOE growth	—	—	—	New“0 to 5%”	—	—	—	—
Three-year outlook annual average oil growth	—	—	—	New“5% or greater”	—	—	—	—
Three-year outlook average annual capital range	—	—	—	New“$2.1 to $2.4 billion”	—	—	—	—
Three-year outlook average reinvestment rate (non-GAAP)	—	—	—	New“below 50%”	—	—	—	—
Total BOE production growth	—	—	—	New“up approximately 9% year-over-year at the mid-point”	—	—	—	—
Total equivalent production	—	—	—	—	New“710 to 760 MBoepd”	Raised“740 to 790 MBoepd”	Raised“770 to 810 MBoepd”	—
Total equivalent production	—	—	—	—	—	—	New“772 to 782 MBoepd”	—
Total equivalent production	—	—	—	—	—	—	New“770 to 810 MBoepd”	—
Total equivalent production	—	—	—	—	New“710 to 760 MBoepd”	—	—	—
Total equivalent production	—	—	—	New“710 to 750 MBoepd”	—	—	—	—
Total equivalent production	—	—	—	New“710 to 770 MBoepd”	—	—	—	—
Total Equivalent Production	—	—	—	—	—	New“740 to 790 MBoepd”	—	—
Total Equivalent Production (MBoed)	—	—	—	—	New“720 — 745 — 770”	Changed“755 — 768 — 780”	Changed“772 — 777 — 782”	—
Total Equivalent Production (MBoed)	—	—	—	—	—	—	New“770 — 790 — 810”	—
Total Equivalent Production (MBoed)	—	—	—	—	—	New“740 — 765 — 790”	—	—
Total Equivalent Production (MBoed)	—	—	—	—	New“710 — 735 — 760”	—	—	—
Total Equivalent Production (MBoed) - 2025 (Low/Mid/High)	—	—	—	New“710 740 770”	—	—	—	—
Total Equivalent Production (MBoed) - Q1 2025 (Low/Mid/High)	—	—	—	New“710 730 750”	—	—	—	—
Unit Operating Cost ($/boe)	—	—	—	—	New“$7.90 — $9.30 — $10.70”	—	Reiterated“$7.90 — $9.30 — $10.70”	—
WTI ($ per bbl)	—	—	—	—	—	—	New“$65”	—
WTI price assumption	—	—	—	—	New“approximately $63 per bbl”	—	—	—
For FY2024
Annual dividend	New“$0.84 per share”	Reiterated“$0.84 per share annual dividend”	Reiterated“$0.84 per share”	—	—	—	—	—
Annual Free Cash Flow returned to shareholders	New“50% or greater”	Reiterated“50% or greater”	Reiterated“50% or greater”	Reiterated“50% or more”	—	—	—	—
BOE production	—	—	New“660 to 675 MBoepd”	—	—	—	—	—
BOE production	—	New“645 to 675”	—	—	—	—	—	—
Capital expenditures	—	—	New“$1.75 to $1.85 billion”	—	—	—	—	—
Capital expenditures - Total Company - Fourth Quarter 2024	—	—	New“$410 — $455 — $500”	—	—	—	—	—
Capital expenditures - Total Company - Full Year	—	—	New“$1,750 — $1,800 — $1,850”	—	—	—	—	—
Capital Expenditures ($ in billions)	—	—	New“$1.75 — $1.80 — $1.85”	—	—	—	—	—
Capital expenditures (non-GAAP)	—	—	New“$1.75 to $1.85 billion”	—	—	—	—	—
Capital expenditures (non-GAAP)	—	—	New“$410 to $500 million”	—	—	—	—	—
Commodity price assumption - Henry Hub ($ per mmbtu)	—	—	New“$2.22”	—	—	—	—	—
Commodity price assumption - WTI ($ per bbl)	—	—	New“$76”	—	—	—	—	—
Discretionary Cash Flow (non-GAAP)	—	—	New“approximately $2.9 billion”	—	—	—	—	—
Discretionary Cash Flow (non-GAAP)	New“approximately $3.1 billion”	Raised“approximately $3.2 billion”	—	—	—	—	—	—
Drilling and completion - Anadarko Basin	New“$270 - $290 - $320”	Changed“$290 midpoint”	Raised“$300 midpoint”	—	—	—	—	—
Drilling and completion - Marcellus Shale	New“$350- $375 -$400”	Changed“$375 midpoint”	Lowered“$300 midpoint”	—	—	—	—	—
Drilling and completion - Permian Basin	New“$945 - $1,000 - $1,055”	Changed“$1,000 midpoint”	Raised“$1,050 midpoint”	—	—	—	—	—
Free Cash Flow (DCF - cash capex)	—	New“$1.3”	—	—	—	—	—	—
Free Cash Flow (DCF - cash capex) ($ in billions)	New“$1.3”	—	Lowered“$1.1”	—	—	—	—	—
Gas (Mmcf/day)	New“2,650 - 2,725 - 2,800”	Changed“2,675 - 2,725 - 2,775”	—	—	—	—	—	—
Gas (Mmcf/day)	—	New“2,500 - 2,565 - 2,630”	—	—	—	—	—	—
Gas (Mmcf/day)	New“2,600 - 2,650 - 2,700”	—	—	—	—	—	—	—
Gas (Mmcf/day) - Fourth Quarter 2024	—	—	New“2,530 — 2,595 — 2,660”	—	—	—	—	—
Gas (Mmcf/day) - Full Year	—	—	New“2,735 — 2,755 — 2,775”	—	—	—	—	—
Gathering, processing, & transportation ($/boe)	New“$3.50 - $4.00 - $4.50”	Reiterated“$3.50 - $4.00 - $4.50”	—	—	—	—	—	—
General & administrative ($/boe)	New“$0.80 - $0.90 - $1.00”	Reiterated“$0.80 - $0.90 - $1.00”	—	—	—	—	—	—
Henry Hub ($ per mmbtu) commodity price assumption	New“$2.35”	—	—	—	—	—	—	—
Henry Hub ($ per mmbtu) commodity price assumption	New“$1.76”	—	—	—	—	—	—	—
Henry Hub commodity price assumption ($ per mmbtu)	—	New“$2.37”	—	—	—	—	—	—
Incurred capital expenditures	New“$470 to $550 million”	Lowered“$450 to $530 million”	—	—	—	—	—	—
Incurred capital expenditures - Total Company	—	New“$450 - $480 - $530”	—	—	—	—	—	—
Incurred capital expenditures - Total Company	New“$1,750 - $1,850 - $1,950”	Reiterated“$1,750 - $1,850 - $1,950”	—	—	—	—	—	—
Incurred capital expenditures - Total Company	New“$470 - $510 - $550”	—	—	—	—	—	—	—
Incurred Capital Expenditures ($ in billions)	New“$1.75 - $1.85 - $1.95”	Reiterated“$1.75 - $1.85 - $1.95”	—	—	—	—	—	—
Incurred capital expenditures (non-GAAP)	New“$1.75 to $1.95 billion”	Reiterated“$1.75 to $1.95 billion”	—	—	—	—	—	—
Incurred capital expenditures (non-GAAP)	—	New“$450 to $530 million”	—	—	—	—	—	—
Incurred capital expenditures (non-GAAP)	New“$470 to $550 million”	—	—	—	—	—	—	—
Lease operating expense + workovers + region office	New“$2.15 - $2.50 - $2.85”	—	—	—	—	—	—	—
Lease operating expense + workovers + region office ($/boe)	—	New“$2.15 - $2.50 - $2.85”	—	—	—	—	—	—
Midstream, saltwater disposal and infrastructure	New“$185 - $185 - $185”	Changed“$185 midpoint”	Lowered“$150 midpoint”	—	—	—	—	—
Natural gas production	—	New“2,675 to 2,775 MMcfpd”	Lowered“2,530 to 2,660 MMcfpd”	—	—	—	—	—
Natural gas production	—	—	New“2,735 to 2,775 MMcfpd”	—	—	—	—	—
Natural gas production	—	—	New“2,530 to 2,660 MMcfpd”	—	—	—	—	—
Natural gas production	—	New“2,500 to 2,630 MMcfpd”	—	—	—	—	—	—
Natural gas production	New“2,600 to 2,700 MMcfpd”	—	—	—	—	—	—	—
Net wells turned in line - Anadarko Basin	New“20 - 23 - 25”	Changed“21 - 24 - 27”	—	—	—	—	—	—
Net wells turned in line - Anadarko Basin	—	New“5”	—	—	—	—	—	—
Net wells turned in line - Anadarko Basin	New“7-10-13”	—	—	—	—	—	—	—
Net wells turned in line - Anadarko Basin - Fourth Quarter 2024	—	—	New“1 — 4 — 7”	—	—	—	—	—
Net wells turned in line - Marcellus Shale	—	New“0 - 4 - 7”	—	—	—	—	—	—
Net wells turned in line - Marcellus Shale	New“37 - 40 - 43”	Reiterated“37 - 40 - 43”	—	—	—	—	—	—
Net wells turned in line - Marcellus Shale	New“0 - 0 - 0”	—	—	—	—	—	—	—
Net wells turned in line - Marcellus Shale - Fourth Quarter 2024	—	—	New“11”	—	—	—	—	—
Net wells turned in line - Marcellus Shale - Full Year	—	—	New“40”	—	—	—	—	—
Net wells turned in line - Permian Basin	New“75 - 83 - 90”	Changed“80 - 85 - 90”	—	—	—	—	—	—
Net wells turned in line - Permian Basin	—	New“15 - 20 - 25”	—	—	—	—	—	—
Net wells turned in line - Permian Basin	New“15 - 23 - 30”	—	—	—	—	—	—	—
Net wells turned in line - Permian Basin - Fourth Quarter 2024	—	—	New“13 — 18 — 23”	—	—	—	—	—
Oil (MBbl/day)	New“102.0 - 104.5 - 107.0”	Changed“105.5 - 107.0 - 108.5”	—	—	—	—	—	—
Oil (MBbl/day)	—	New“107.0 - 109.0 - 111.0”	—	—	—	—	—	—
Oil (MBbl/day)	New“103.0 - 105.0 - 107.0”	—	—	—	—	—	—	—
Oil (MBbl/day) - Fourth Quarter 2024	—	—	New“106.0 — 108.0 — 110.0”	—	—	—	—	—
Oil (MBbl/day) - Full Year	—	—	New“107 — 107.5 — 108”	—	—	—	—	—
Oil production	New“102 to 107 MBopd”	Raised“105.5 to 108.5 MBopd”	Raised“106 to 110 MBopd”	—	—	—	—	—
Oil production	—	—	New“107 to 108 MBopd”	—	—	—	—	—
Oil production	—	—	New“106 to 110 MBopd”	—	—	—	—	—
Oil production	—	New“107.0 to 111.0 MBopd”	—	—	—	—	—	—
Oil production	New“103 to 107 MBopd”	—	—	—	—	—	—	—
Quarterly base dividend	—	—	New“$0.21 per share”	—	—	—	—	—
Quarterly dividend increase	—	—	—	New“5% dividend increase to $0.22 per share”	—	—	—	—
Shareholder return commitment (% of annual Free Cash Flow)	New“50% or greater”	—	Reiterated“50% or greater”	—	—	—	—	—
Taxes other than income ($/boe)	New“$1.00 - $1.10 - $1.20”	Reiterated“$1.00 - $1.10 - $1.20”	—	—	—	—	—	—
Total equivalent production	—	—	New“630 to 660 MBoepd”	—	—	—	—	—
Total equivalent production	—	—	New“630 to 660 MBoepd”	—	—	—	—	—
Total equivalent production	—	New“620 to 650 MBoepd”	—	—	—	—	—	—
Total equivalent production	New“625 to 655 MBoepd”	—	—	—	—	—	—	—
Total Equivalent Production (MBoed)	New“635 - 655 - 675”	Changed“645 - 660 - 675”	—	—	—	—	—	—
Total Equivalent Production (MBoed)	—	New“620 - 635 - 650”	—	—	—	—	—	—
Total Equivalent Production (MBoed)	New“625 - 640 - 655”	—	—	—	—	—	—	—
Total Equivalent Production (MBoed) - Fourth Quarter 2024	—	—	New“630 — 645 — 660”	—	—	—	—	—
Total Equivalent Production (MBoed) - Full Year	—	—	New“660 — 668 — 675”	—	—	—	—	—
Unit Operating Cost ($/boe)	New“$7.45 - $8.50 - $9.55”	Reiterated“$7.45 - $8.50 - $9.55”	—	—	—	—	—	—
Windham Row wells expected online by end of year	—	—	New“10 additional wells”	—	—	—	—	—
Workovers + region office ($/boe)	New“$2.15 - $2.50 - $2.85”	—	—	—	—	—	—	—
WTI ($ per bbl) commodity price assumption	New“$79”	—	—	—	—	—	—	—
WTI ($ per bbl) commodity price assumption	New“$82”	—	—	—	—	—	—	—
WTI commodity price assumption ($ per bbl)	—	New“$80”	—	—	—	—	—	—
No period stated
Net Debt to Adjusted EBITDAX leverage ratio	—	—	—	New“below 1.0x”	—	—	—	—
Net Debt to Adjusted EBITDAX leverage ratio target	—	—	—	New“below 1.0x”	—	—	—	—
Net Debt to Adjusted EBITDAX ratio (non-GAAP)	—	—	—	—	—	—	—	New“below 1.0x”
Net Debt to Adjusted EBITDAX ratio (non-GAAP)	—	—	—	—	—	—	—	New“below 1.0x”
Annualized dividend yield	—	—	—	—	New“3.4% annualized yield”	—	—	—
Incremental capital (second rig option through year-end)	—	—	—	—	New“an incremental $50 million”	—	—	—
New annualized dividend	—	—	—	New“$0.88 per share”	—	—	—	—
Quarterly base dividend	New“$0.21 per share”	Reiterated“$0.21 per share”	—	Raised“$0.22 per share”	—	—	—	—
Quarterly dividend	—	—	—	—	New“$0.22 per share”	—	—	—
Share Repurchase Authorization Remaining	—	—	—	—	—	New“$1.1 billion”	—	—
Shareholder return commitment	—	New“50% or greater of annual Free Cash Flow (non-GAAP)”	—	—	—	—	—	—
Shareholder return target	—	—	—	New“50% or more of its annual Free Cash Flow (non-GAAP)”	Reiterated“50% or greater of annual Free Cash Flow (non-GAAP)”	—	—	—
Shareholder Return Target (Dividends + Buybacks)	—	—	—	—	—	New“50% or greater of annual Free Cash Flow (non-GAAP)”	—	—
Shareholder returns	—	—	—	—	—	New“50% or greater of annual Free Cash Flow (non-GAAP)”	Reiterated“50% or greater of Free Cash Flow (non-GAAP)”	—
Shareholder returns (% of Free Cash Flow)	—	—	—	—	—	—	New“50% or greater”	—

Values in quotation marks are the company’s words. Change labels compare each statement with the same metric and target year in the previous release. HighGravityData does not judge whether guidance was met.