News Release
Coterra Energy Reports Fourth-Quarter and Full-Year 2023 Results, Provides 2024 Outlook, and Announces Dividend Increase
HOUSTON, February 22, 2024 - Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported fourth-quarter and full-year 2023 results, provided first-quarter and full-year 2024 guidance and released a new three-year outlook for 2024 through 2026. The Company also declared a quarterly dividend of $0.21 per share, a 5% increase year-over-year.
Key Takeaways & Updates
•For the fourth quarter of 2023, total barrels of oil equivalent and oil production beat the high-end of guidance and incurred capital expenditures (non-GAAP) came in below the low-end of guidance.
•Relative to our initial full-year 2023 guidance, total barrels of oil equivalent and oil production beat the high-end of guidance by 3% and 5%, respectively, and incurred capital expenditures (non-GAAP) came in at the mid-point of guidance.
•Shareholder returns totaled 77% of 2023 Free Cash Flow (non-GAAP). The Company remains committed to returning 50%+ of its annual Free Cash Flow (non-GAAP) to shareholders.
•Declared $0.21 per share dividend for the fourth quarter of 2023, or $0.84 per share annualized, representing a 5% increase year-over-year, and equating to a 3.2% yield, based on the Company's $26.16 closing share price as of February 21, 2024.
•2024 incurred capital expenditures (non-GAAP) are expected to be between $1.75 and $1.95 billion, down 12% year-over-year at the mid-point driven by lower Marcellus activity and expected cost reductions. 2024 total barrel of oil equivalent production is expected to be down approximately 2% year-over-year at the mid-point, with oil volumes up approximately 6% and natural gas volumes down approximately 6%, at the mid-point.
•New three-year outlook (2024 through 2026), guiding to 0-5% barrel of oil equivalent and 5+% oil CAGRs, based on annual incurred capital expenditures (non-GAAP) averaging between $1.75-$1.95 billion.
Tom Jorden, Chairman, CEO and President of Coterra, noted, “Coterra’s outstanding 2023 results were driven by our commitment to operational excellence, coupled with strong execution in the field. The Company invested at the mid-point of capital guidance and beat the high-end of production guidance, which was driven by a combination of strong well productivity and field efficiency gains. As we look ahead, our 2024 capital plan underscores Coterra’s ability to pivot capital as fundamentals in the commodity markets dictate. Our disciplined, economically driven approach reduces total capital investment by roughly 12% year over year driven by lower natural-gas focused investments partially offset by a modest increase of investment in our liquids-rich basins. The company maintains optionality to further pivot capital in the future, should macro conditions warrant.”
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Mr. Jorden continued, “Our new three-year outlook, which calls for 0-5% BOE growth and 5+% oil growth at an average $1.75-$1.95 billion capital spend, underscores the Company’s ability to continue to improve its capital efficiency. Capital discipline, allocating capital to its most productive use, consistent, profitable growth, and maintaining a fortress balance sheet are key to Coterra’s investment strategy and allow us to provide a robust shareholder return program through the cycles.”
Fourth-Quarter 2023 Highlights
•Net Income (GAAP) totaled $416 million, or $0.55 per share. Adjusted Net Income (non-GAAP) was $387 million, or $0.52 per share.
•Cash Flow From Operating Activities (GAAP) totaled $760 million. Discretionary Cash Flow (non-GAAP) totaled $881 million.
•Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $468 million. Incurred capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) totaled $457 million, below the low end of our guidance range of $460 to $530 million.
•Free Cash Flow (non-GAAP) totaled $413 million.
•Unit operating cost (reflecting costs from direct operations, transportation, production taxes, and G&A) totaled $8.41 per BOE (barrel of oil equivalent), within our annual guidance range set at $7.30-$9.40 per BOE.
•Total equivalent production of 697 MBoepd (thousand barrels of oil equivalent per day), exceeded the high end of guidance (645 to 680 MBoepd), driven by improved cycle times and strong well performance.
◦Oil production averaged 104.7 MBopd (thousand barrels of oil per day), exceeding the high end of guidance (98 - 102 MBopd).
◦Natural gas production averaged 2,970 MMcfpd (million cubic feet per day), exceeding the high end of guidance (2,780 to 2,900 MMcfpd).
◦Natural Gas Liquids (NGLs) production averaged 97.8 MBoepd.
•Realized average prices:
◦Oil was $77.10 per barrel (Bbl), excluding the effect of commodity derivatives, and $77.21 per Bbl, including the effect of commodity derivatives.
◦Natural Gas was $2.03 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $2.19 per Mcf, including the effect of commodity derivatives.
◦NGLs were $18.66 per BOE.
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2024 Outlook
•Estimate Discretionary Cash Flow (non-GAAP) of approximately $3.15 billion and Free Cash Flow (non-GAAP) of approximately $1.3 billion, at approximately flat $75/bbl and $2.50/mmbtu pricing.
•Expect 2024 incurred capital expenditures (non-GAAP) of $1.75 - $1.95 billion
◦Mid-point down approximately $250 million relative to 2023, primarily due to lower Marcellus spending and lower service cost expectations. Modestly increasing Permian and Anadarko capital expenditures.
◦Total Marcellus drilling and completion capital expenditures estimated to be approximately $350 - 400 million, down approximately 55% or approximately $460 million year-over-year at the mid-point. As a result, Marcellus volumes are expected to be down 6% year-over-year.
•Expect 2024 total equivalent production of 635-675 MBoepd, down approximately 2% year-over-year at the mid-point; oil production of 99-105 MBopd, up approximately 6% year-over-year at the mid-point; and natural gas production of 2,650 - 2,800 MMcfpd, down approximately 6% year-over-year at the mid-point.
•Expect 1Q24 total equivalent production of 660 to 690 MBoepd, oil production of 95 to 99 MBopd, natural gas production of 2,850 to 2,950 MMcfpd, and capital expenditures of $460 to $540 million.
Three Year Outlook: 2024-2026
•New three-year outlook (2024 through 2026), guiding to 0-5% barrel of oil equivalent and 5+% oil CAGRs, based on annual incurred capital expenditures (non-GAAP) averaging between $1.75 - $1.95 billion.
•The Company maintains significant flexibility to adjust its total capital investment level and allocation of capital across its three basins. This flexibility is supported by limited long-term service contracts. While the Company is choosing to lower natural gas-directed activity in 2024, it maintains options that could significantly grow natural gas volumes over the next three years.
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Full-Year 2023 and Fourth Quarter 2023 Shareholder Return Highlights
•Common Dividend: On February 22, 2024, Coterra's Board of Directors (the "Board") approved a quarterly base dividend of $0.21 per share, which is a 5% increase year-over-year. The dividend will be paid on March 28, 2024 to holders of record on March 14, 2024.
•Share Repurchases: During the quarter, the Company repurchased 1.1 million shares for $29 million at a weighted-average price of $26.84 per share. During 2023, the Company repurchased 17 million shares for $418 million (including 1% excise tax) at a weighted-average price of $25.01 per share. $1.6 billion remains on the $2.0 billion share repurchase authorization as of December 31, 2023.
•Total Shareholder Return: During the quarter, total shareholder returns amounted to $187 million, composed of $158 million of declared dividends and $29 million of share repurchases. In 2023, total shareholder returns amounted to $1,026 million, composed of $612 million of declared dividends and $414 million of share repurchases (excluding accrued excise tax), representing 77% of 2023 Free Cash Flow (non-GAAP).
•Shareholder Return Strategy: Coterra reaffirms its commitment to returning 50% or more of its annual Free Cash Flow (non-GAAP) to shareholders primarily through its base dividends and share repurchases.
Full-Year 2023 Highlights
•Net Income (GAAP) totaled $1,625 million, or $2.14 per share. Adjusted Net Income (non-GAAP) was $1,712 million, or $2.26 per share.
•Cash Flow From Operating Activities (GAAP) totaled $3,658 million. Discretionary Cash Flow (non-GAAP) totaled $3,421 million.
•Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $2,089 million. Incurred capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) totaled $2,104 million, in line with the mid-point of our guidance range of $2.0 to $2.2 billion.
•Free Cash Flow (non-GAAP) totaled $1,332 million. Unit operating cost (reflecting costs from direct operations, transportation, production taxes, and G&A) totaled $8.37 per BOE, within our annual guidance range of $7.30-$9.40 per BOE.
•Total equivalent production of 667 MBoepd, exceeded the high end of initial guidance (610 to 650 MBoepd), driven by improved cycle times and strong well performance.
◦Oil production averaged 96.2 MBopd, exceeding the high end of initial guidance (86 to 92 MBopd).
◦Natural gas production averaged 2,884 MMcfpd, exceeding the high end of initial guidance (2,700 to 2,850 MMcfpd).
◦NGLs production averaged 90.2 MBoepd.
•Realized average prices:
◦Oil: $75.97 per Bbl, excluding the effect of commodity derivatives, and $76.07 per Bbl, including the effect of commodity derivatives
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◦Natural Gas: $2.18 per Mcf, excluding the effect of commodity derivatives, and $2.44 per Mcf, including the effect of commodity derivatives
◦NGLs: $19.56 per BOE
Strong Financial Position
As of December 31, 2023, Coterra had total debt of $2.161 billion with a principal amount of $2.075 billion, of which $575 million is due in September 2024. The Company ended the year with a cash balance of $956 million and no debt outstanding under its revolving credit facility, resulting in total liquidity of approximately $2.46 billion. Coterra's net debt to trailing twelve-month EBITDAX ratio (non-GAAP) at December 31, 2023 was 0.3x.
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.
2023 Proved Reserves
At December 31, 2023, Coterra's proved reserves totaled 2,321 million barrels of oil equivalent (MMBoe), down approximately 3% year-over-year, primarily driven by lower year-over-year SEC commodity prices. SEC commodity prices underpinning our proved reserves in 2023 for oil, natural gas liquids and natural gas, adjusted for basis and quality differentials, are $75.05 per Bbl, $18.39 per Bbl and $2.04 per Mcf, respectively, down from 2022 prices of $94.21 per Bbl, $31.45 per Bbl and $5.25 per Mcf.
The Company had net negative revisions of prior estimates of 60 MMBoe which included an 83 MMBoe negative revision due to price and a 10 MMBoe negative revision due to increases in operating expenses, partially offset by a positive 33 MMBoe performance revision. Excluding the SEC 5-year rule, there was a positive technical revision in the Marcellus Shale.
At December 31, 2023, the company’s proved undeveloped reserves were 21% of total proved reserves, down from 24% at year-end 2022. This decrease was driven primarily by the company’s decision to reduce proved undeveloped additions to provide more capital investment flexibility across its three core operating regions.
For a summary of Coterra's estimated proved reserves at December 31, 2023, see the "Year-End Proved Reserves" table below and in our annual report on Form 10-K for the fiscal year ended December 31, 2023.
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.
Conference Call
Coterra will host a conference call tomorrow, Friday, February 23, 2024, at 9:00 AM CT (10:00 AM ET), to discuss fourth-quarter and full-year 2023 financial and operating results and its 2024 outlook.
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Conference Call Information
Date: Friday, February 23, 2024
Time: 9:00 AM CT / 10:00 AM ET
Dial-in (for callers in the U.S. and Canada): (888) 550-5424
International dial-in: (646) 960-0819
Conference ID: 3813676
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 focused operations 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 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 (such as the coronavirus pandemic) and epidemics and any related governmental policies or actions on Coterra’s business, 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 (including as a result of the pandemic or geopolitical disruptions such as the war in Ukraine or conflict in the Middle East); 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
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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 December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| PRODUCTION VOLUMES | |||||||||||||||||||||||
| Marcellus Shale | |||||||||||||||||||||||
| Natural gas (Mmcf/day) | 2,304.9 | 2,143.2 | 2,262.7 | 2,204.3 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 384.2 | 357.2 | 377.1 | 367.4 | |||||||||||||||||||
| Permian Basin | |||||||||||||||||||||||
| Natural gas (Mmcf/day) | 482.0 | 442.3 | 440.8 | 424.4 | |||||||||||||||||||
| Oil (MBbl/day) | 97.3 | 83.0 | 89.5 | 81.2 | |||||||||||||||||||
| NGL (MBbl/day) | 76.9 | 57.6 | 70.5 | 59.5 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 254.5 | 214.3 | 233.4 | 211.4 | |||||||||||||||||||
| Anadarko Basin | |||||||||||||||||||||||
| Natural gas (Mmcf/day) | 179.4 | 193.6 | 178.9 | 176.2 | |||||||||||||||||||
| Oil (MBbl/day) | 6.7 | 7.5 | 6.5 | 6.2 | |||||||||||||||||||
| NGL (MBbl/day) | 20.7 | 20.5 | 19.7 | 19.0 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 57.3 | 60.2 | 56.0 | 54.6 | |||||||||||||||||||
| Total Company | |||||||||||||||||||||||
| Natural gas (Mmcf/day) | 2,970.0 | 2,780.4 | 2,884.2 | 2,806.5 | |||||||||||||||||||
| Oil (MBbl/day) | 104.7 | 90.7 | 96.2 | 87.5 | |||||||||||||||||||
| NGL (MBbl/day) | 97.8 | 78.1 | 90.2 | 78.6 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 697.4 | 632.2 | 667.1 | 633.8 | |||||||||||||||||||
| AVERAGE SALES PRICE (excluding hedges) | |||||||||||||||||||||||
| Marcellus Shale | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 2.17 | $ | 5.16 | $ | 2.33 | $ | 5.29 | |||||||||||||||
| Permian Basin | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 1.19 | $ | 3.22 | $ | 1.28 | $ | 5.18 | |||||||||||||||
| Oil ($/Bbl) | $ | 77.26 | $ | 82.27 | $ | 75.98 | $ | 94.55 | |||||||||||||||
| NGL ($/Bbl) | $ | 17.65 | $ | 23.40 | $ | 18.44 | $ | 32.59 | |||||||||||||||
| Anadarko Basin | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 2.30 | $ | 5.44 | $ | 2.37 | $ | 6.29 | |||||||||||||||
| Oil ($/Bbl) | $ | 79.12 | $ | 81.94 | $ | 76.92 | $ | 93.34 | |||||||||||||||
| NGL ($/Bbl) | $ | 22.40 | $ | 29.60 | $ | 23.54 | $ | 36.66 | |||||||||||||||
| Total Company | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 2.03 | $ | 4.87 | $ | 2.18 | $ | 5.34 | |||||||||||||||
| Oil ($/Bbl) | $ | 77.10 | $ | 82.26 | $ | 75.97 | $ | 94.47 | |||||||||||||||
| NGL ($/Bbl) | $ | 18.66 | $ | 25.02 | $ | 19.56 | $ | 33.58 | |||||||||||||||
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| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| AVERAGE SALES PRICE (including hedges) | |||||||||||||||||||||||
| Total Company | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 2.19 | $ | 4.74 | $ | 2.44 | $ | 4.91 | |||||||||||||||
| Oil ($/Bbl) | $ | 77.21 | $ | 81.57 | $ | 76.07 | $ | 84.33 | |||||||||||||||
| NGL ($/Bbl) | $ | 18.66 | $ | 25.02 | $ | 19.56 | $ | 33.58 | |||||||||||||||
| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
WELLS DRILLED(1) | |||||||||||||||||||||||
| Gross wells | |||||||||||||||||||||||
| Marcellus Shale | 20 | 27 | 73 | 93 | |||||||||||||||||||
| Permian Basin | 44 | 43 | 159 | 161 | |||||||||||||||||||
| Anadarko Basin | 2 | 9 | 32 | 31 | |||||||||||||||||||
| 66 | 79 | 264 | 285 | ||||||||||||||||||||
| Net wells | |||||||||||||||||||||||
| Marcellus Shale | 16.2 | 27.0 | 69.2 | 93.0 | |||||||||||||||||||
| Permian Basin | 18.6 | 13.7 | 82.1 | 72.7 | |||||||||||||||||||
| Anadarko Basin | 1.8 | 0.1 | 18.1 | 8.9 | |||||||||||||||||||
| 36.6 | 40.8 | 169.4 | 174.6 | ||||||||||||||||||||
| TURN IN LINES | |||||||||||||||||||||||
| Gross wells | |||||||||||||||||||||||
| Marcellus Shale | 12 | 26 | 71 | 81 | |||||||||||||||||||
| Permian Basin | 61 | 39 | 183 | 144 | |||||||||||||||||||
| Anadarko Basin | 3 | 11 | 19 | 26 | |||||||||||||||||||
| 76 | 76 | 273 | 251 | ||||||||||||||||||||
| Net wells | |||||||||||||||||||||||
| Marcellus Shale | 12.0 | 26.0 | 71.0 | 78.1 | |||||||||||||||||||
| Permian Basin | 28.0 | 13.5 | 94.9 | 61.3 | |||||||||||||||||||
| Anadarko Basin | — | 5.9 | 7.1 | 8.7 | |||||||||||||||||||
| 40.0 | 45.4 | 173.0 | 148.1 | ||||||||||||||||||||
| AVERAGE RIG COUNTS | |||||||||||||||||||||||
| Marcellus Shale | 2.6 | 2.9 | |||||||||||||||||||||
| Permian Basin | 6.5 | 6.2 | |||||||||||||||||||||
| Anadarko Basin | 1.3 | 0.9 | |||||||||||||||||||||
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| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
AVERAGE UNIT COSTS ($/Boe)(2) | |||||||||||||||||||||||
| Direct operations | $ | 2.51 | $ | 2.17 | $ | 2.31 | $ | 1.99 | |||||||||||||||
| Gathering, processing and transportation | 3.83 | 3.94 | 4.00 | 4.13 | |||||||||||||||||||
| Taxes other than income | 1.12 | 1.55 | 1.16 | 1.58 | |||||||||||||||||||
| General and administrative (excluding stock-based compensation and merger-related expense) | 0.95 | 1.17 | 0.90 | 1.03 | |||||||||||||||||||
| Unit Operating Cost | $ | 8.41 | $ | 8.83 | $ | 8.37 | $ | 8.73 | |||||||||||||||
| Depreciation, depletion and amortization | 7.11 | 7.54 | 6.74 | 7.07 | |||||||||||||||||||
| Exploration | 0.08 | 0.11 | 0.08 | 0.13 | |||||||||||||||||||
| Stock-based compensation | 0.23 | 0.28 | 0.24 | 0.37 | |||||||||||||||||||
| Merger-related expense | — | — | — | 0.03 | |||||||||||||||||||
| Severance expense | 0.03 | 0.18 | 0.05 | 0.27 | |||||||||||||||||||
| Interest expense | 0.13 | 0.17 | 0.11 | 0.30 | |||||||||||||||||||
| $ | 16.00 | $ | 17.11 | $ | 15.60 | $ | 16.90 | ||||||||||||||||
_______________________________________________________________________________
(1)Wells drilled represents wells drilled to total depth during the period. Wells completed includes wells completed during the period, regardless of when they were drilled.
(2)Total unit costs may differ from the sum of the individual costs due to rounding.
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Derivatives Information
As of December 31, 2023, the Company had the following outstanding financial commodity derivatives:
2024 | ||||||||||||||||||||||||||
| Natural Gas | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||
| NYMEX collars | ||||||||||||||||||||||||||
| Volume (MMBtu) | 35,490,000 | 44,590,000 | 45,080,000 | 16,690,000 | ||||||||||||||||||||||
Weighted average floor ($/MMBtu) | $ | 3.00 | $ | 2.70 | $ | 2.75 | $ | 2.75 | ||||||||||||||||||
Weighted average ceiling ($/MMBtu) | $ | 5.38 | $ | 3.87 | $ | 3.94 | $ | 4.23 | ||||||||||||||||||
| 2025 | ||||||||||||||||||||||||||
| Natural Gas | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||
NYMEX collars | ||||||||||||||||||||||||||
| Volume (MMBtu) | 9,000,000 | 9,100,000 | 9,200,000 | 9,200,000 | ||||||||||||||||||||||
Weighted average floor ($/MMBtu) | $ | 3.25 | $ | 3.25 | $ | 3.25 | $ | 3.25 | ||||||||||||||||||
Weighted average ceiling ($/MMBtu) | $ | 4.79 | $ | 4.79 | $ | 4.79 | $ | 4.79 | ||||||||||||||||||
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| 2024 | ||||||||||||||||||||||||||
| Oil | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||
| WTI oil collars | ||||||||||||||||||||||||||
| Volume (MBbl) | 2,730 | 2,730 | 1,840 | 1,840 | ||||||||||||||||||||||
| Weighted average floor ($/Bbl) | $ | 68.00 | $ | 68.00 | $ | 65.00 | $ | 65.00 | ||||||||||||||||||
| Weighted average ceiling ($/Bbl) | $ | 91.37 | $ | 91.37 | $ | 90.01 | $ | 90.01 | ||||||||||||||||||
| WTI Midland oil basis swaps | ||||||||||||||||||||||||||
| Volume (MBbl) | 2,730 | 2,730 | 1,840 | 1,840 | ||||||||||||||||||||||
| Weighted average differential ($/Bbl) | $ | 1.16 | $ | 1.16 | $ | 1.17 | $ | 1.17 | ||||||||||||||||||
In January 2024, the Company entered into the following financial commodity derivatives:
| 2024 | ||||||||||||||||||||||||||
| Oil | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||
| WTI oil collars | ||||||||||||||||||||||||||
| Volume (MBbl) | 300 | 455 | 920 | 920 | ||||||||||||||||||||||
| Weighted average floor ($/Bbl) | $ | 65.00 | $ | 65.00 | $ | 65.00 | $ | 65.00 | ||||||||||||||||||
| Weighted average ceiling ($/Bbl) | $ | 85.02 | $ | 85.02 | $ | 81.49 | $ | 81.49 | ||||||||||||||||||
| WTI Midland oil basis swaps | ||||||||||||||||||||||||||
| Volume (MBbl) | 300 | 455 | 920 | 920 | ||||||||||||||||||||||
| Weighted average differential ($/Bbl) | $ | 1.10 | $ | 1.10 | $ | 1.10 | $ | 1.10 | ||||||||||||||||||
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Year-End Proved Reserves
The tables below provide a summary of changes in proved reserves for the year ended December 31, 2023.
| Oil (MBbl) | Natural Gas (Bcf) | NGL (MBbl) | Total (MBOE) | ||||||||||||||||||||
| PROVED RESERVES | |||||||||||||||||||||||
| December 31, 2022 | 239,755 | 11,173 | 296,765 | 2,398,666 | |||||||||||||||||||
| Revision of previous estimates | 1,084 | (414) | 8,067 | (59,970) | |||||||||||||||||||
| Extensions and discoveries | 44,386 | 823 | 46,148 | 227,660 | |||||||||||||||||||
| Production | (35,110) | (1,053) | (32,932) | (243,497) | |||||||||||||||||||
| Sales of reserves | (902) | (4) | (592) | (2,102) | |||||||||||||||||||
| December 31, 2023 | 249,213 | 10,525 | 317,456 | 2,320,757 | |||||||||||||||||||
| PROVED DEVELOPED RESERVES | |||||||||||||||||||||||
| December 31, 2022 | 168,649 | 8,543 | 224,706 | 1,817,140 | |||||||||||||||||||
| December 31, 2023 | 173,392 | 8,590 | 234,306 | 1,839,219 | |||||||||||||||||||
12
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| (In millions, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| OPERATING REVENUES | |||||||||||||||||||||||
| Natural gas | $ | 553 | $ | 1,246 | $ | 2,292 | $ | 5,469 | |||||||||||||||
| Oil | 742 | 686 | 2,667 | 3,016 | |||||||||||||||||||
| NGL | 168 | 180 | 644 | 964 | |||||||||||||||||||
| Gain (loss) on derivative instruments | 101 | 150 | 230 | (463) | |||||||||||||||||||
| Other | 32 | 18 | 81 | 65 | |||||||||||||||||||
| 1,596 | 2,280 | 5,914 | 9,051 | ||||||||||||||||||||
| OPERATING EXPENSES | |||||||||||||||||||||||
| Direct operations | 161 | 126 | 562 | 460 | |||||||||||||||||||
| Gathering, processing and transportation | 246 | 229 | 975 | 955 | |||||||||||||||||||
| Taxes other than income | 72 | 90 | 283 | 366 | |||||||||||||||||||
| Exploration | 6 | 6 | 20 | 29 | |||||||||||||||||||
| Depreciation, depletion and amortization | 456 | 439 | 1,641 | 1,635 | |||||||||||||||||||
| General and administrative (excluding stock-based compensation, severance expense and merger-related costs) | 61 | 68 | 220 | 241 | |||||||||||||||||||
Stock-based compensation(1) | 15 | 16 | 59 | 86 | |||||||||||||||||||
| Merger-related expense | — | — | — | 7 | |||||||||||||||||||
| Severance expense | 2 | 11 | 12 | 62 | |||||||||||||||||||
| 1,019 | 985 | 3,772 | 3,841 | ||||||||||||||||||||
| Gain (loss) on sale of assets | — | — | 12 | (1) | |||||||||||||||||||
| INCOME FROM OPERATIONS | 577 | 1,295 | 2,154 | 5,209 | |||||||||||||||||||
| Interest expense | 23 | 17 | 73 | 80 | |||||||||||||||||||
| Interest income | (15) | (6) | (47) | (10) | |||||||||||||||||||
| Gain on debt extinguishment | — | (2) | — | (28) | |||||||||||||||||||
| Other income | — | (2) | — | (2) | |||||||||||||||||||
| Income before income taxes | 569 | 1,288 | 2,128 | 5,169 | |||||||||||||||||||
| Income tax expense | 153 | 256 | 503 | 1,104 | |||||||||||||||||||
| NET INCOME | $ | 416 | $ | 1,032 | $ | 1,625 | $ | 4,065 | |||||||||||||||
| Earnings per share - Basic | $ | 0.55 | $ | 1.32 | $ | 2.14 | $ | 5.09 | |||||||||||||||
| Weighted-average common shares outstanding | 751 | 781 | 756 | 796 | |||||||||||||||||||
(1)Includes the impact of our performance share awards and restricted stock.
13
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
| (In millions) | December 31, 2023 | December 31, 2022 | |||||||||
| ASSETS | |||||||||||
| Current assets | $ | 2,015 | $ | 2,211 | |||||||
| Properties and equipment, net (successful efforts method) | 17,933 | 17,479 | |||||||||
| Other assets | 467 | 464 | |||||||||
| $ | 20,415 | $ | 20,154 | ||||||||
| LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | |||||||||||
| Current liabilities | $ | 1,085 | $ | 1,193 | |||||||
| Current portion of long-term debt | 575 | — | |||||||||
| Long-term debt, net (excluding current maturities) | 1,586 | 2,181 | |||||||||
| Deferred income taxes | 3,413 | 3,339 | |||||||||
| Other long term liabilities | 709 | 771 | |||||||||
| Cimarex redeemable preferred stock | 8 | 11 | |||||||||
| Stockholders’ equity | 13,039 | 12,659 | |||||||||
| $ | 20,415 | $ | 20,154 | ||||||||
14
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||||||||
| Net income | $ | 416 | $ | 1,032 | $ | 1,625 | $ | 4,065 | |||||||||||||||
| Depreciation, depletion and amortization | 456 | 439 | 1,641 | 1,635 | |||||||||||||||||||
| Deferred income tax expense | 55 | 107 | 74 | 235 | |||||||||||||||||||
| (Gain) loss on sale of assets | — | — | (12) | 1 | |||||||||||||||||||
| (Gain) loss on derivative instruments | (101) | (150) | (230) | 463 | |||||||||||||||||||
| Net cash received (paid) in settlement of derivative instruments | 46 | (39) | 284 | (762) | |||||||||||||||||||
| Stock-based compensation and other | 14 | 11 | 57 | 73 | |||||||||||||||||||
| Income charges not requiring cash | (5) | (7) | (18) | (68) | |||||||||||||||||||
| Changes in assets and liabilities | (121) | 91 | 237 | (186) | |||||||||||||||||||
| Net cash provided by operating activities | 760 | 1,484 | 3,658 | 5,456 | |||||||||||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||||||||||||||
| Capital expenditures for drilling, completion and other fixed asset additions | (468) | (501) | (2,089) | (1,700) | |||||||||||||||||||
| Capital expenditures for leasehold and property acquisitions | (2) | (4) | (10) | (10) | |||||||||||||||||||
| Proceeds from sale of assets | — | 14 | 40 | 36 | |||||||||||||||||||
| Net cash used in investing activities | (470) | (491) | (2,059) | (1,674) | |||||||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||||||||||||||
| Net borrowings (repayments) of debt | — | (44) | — | (874) | |||||||||||||||||||
| Repayments of finance leases | (2) | (2) | (6) | (6) | |||||||||||||||||||
| Common stock repurchases | (20) | (510) | (405) | (1,250) | |||||||||||||||||||
| Dividends paid | (151) | (533) | (890) | (1,992) | |||||||||||||||||||
| Cash paid for conversion of redeemable preferred stock | — | — | (1) | (10) | |||||||||||||||||||
| Tax withholding on vesting of stock awards | (9) | (10) | (10) | (25) | |||||||||||||||||||
| Capitalized debt issuance costs | — | — | (7) | — | |||||||||||||||||||
| Cash received for stock option exercises | 1 | 1 | 2 | 12 | |||||||||||||||||||
| Net cash used in financing activities | (181) | (1,098) | (1,317) | (4,145) | |||||||||||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | $ | 109 | $ | (105) | $ | 282 | $ | (363) | |||||||||||||||
15
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, merger-related expenses 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 December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| (In millions, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| As reported - net income | $ | 416 | $ | 1,032 | $ | 1,625 | $ | 4,065 | |||||||||||||||
| Reversal of selected items: | |||||||||||||||||||||||
| (Gain) loss on sale of assets | — | — | (12) | 1 | |||||||||||||||||||
(Gain) loss on derivative instruments(1) | (55) | (189) | 54 | (299) | |||||||||||||||||||
| Gain on debt extinguishment | — | (2) | — | (28) | |||||||||||||||||||
| Stock-based compensation expense | 15 | 16 | 59 | 86 | |||||||||||||||||||
| Severance expense | 2 | 11 | 12 | 62 | |||||||||||||||||||
| Merger-related expense | — | — | — | 7 | |||||||||||||||||||
| Tax effect on selected items | 9 | 37 | (26) | 38 | |||||||||||||||||||
| Adjusted net income | $ | 387 | $ | 905 | $ | 1,712 | $ | 3,932 | |||||||||||||||
| As reported - earnings per share | $ | 0.55 | $ | 1.32 | $ | 2.14 | $ | 5.09 | |||||||||||||||
| Per share impact of selected items | (0.03) | (0.16) | 0.12 | (0.15) | |||||||||||||||||||
| Adjusted earnings per share | $ | 0.52 | $ | 1.16 | $ | 2.26 | $ | 4.94 | |||||||||||||||
| Weighted-average common shares outstanding | 751 | 781 | 756 | 796 | |||||||||||||||||||
_______________________________________________________________________________
(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.
16
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 December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||
| Cash flow from operating activities | $ | 760 | $ | 1,484 | $ | 3,658 | $ | 5,456 | ||||||||||||||||||
| Changes in assets and liabilities | 121 | (91) | (237) | 186 | ||||||||||||||||||||||
| Discretionary cash flow | 881 | 1,393 | 3,421 | 5,642 | ||||||||||||||||||||||
| Cash paid for capital expenditures for drilling, completion and other fixed asset additions | (468) | (501) | (2,089) | (1,700) | ||||||||||||||||||||||
| Free cash flow | $ | 413 | $ | 892 | $ | 1,332 | $ | 3,942 | ||||||||||||||||||
Capital Expenditures
| Quarter Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||
| Capital expenditures for drilling, completion and other fixed asset additions | $ | 468 | $ | 501 | $ | 2,089 | $ | 1,700 | ||||||||||||||||||
| Change in accrued capital costs | (11) | (22) | 15 | 27 | ||||||||||||||||||||||
| Capital expenditures | $ | 457 | $ | 479 | $ | 2,104 | $ | 1,727 | ||||||||||||||||||
17
Reconciliation of Adjusted EBITDAX
Adjusted EBITDAX is defined as net income plus interest expense, other expense, 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, severance expense and merger-related 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 December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income | $ | 416 | $ | 1,032 | $ | 1,625 | $ | 4,065 | |||||||||||||||
| Plus (less): | |||||||||||||||||||||||
| Interest expense | 23 | 17 | 73 | 80 | |||||||||||||||||||
| Interest income | (15) | (6) | (47) | (10) | |||||||||||||||||||
| Gain on debt extinguishment | — | (2) | — | (28) | |||||||||||||||||||
| Other income | — | (2) | — | (2) | |||||||||||||||||||
| Income tax expense | 153 | 256 | 503 | 1,104 | |||||||||||||||||||
| Depreciation, depletion and amortization | 456 | 439 | 1,641 | 1,635 | |||||||||||||||||||
| Exploration | 6 | 6 | 20 | 29 | |||||||||||||||||||
| (Gain) loss on sale of assets | — | — | (12) | 1 | |||||||||||||||||||
| Non-cash (gain) loss on derivative instruments | (55) | (189) | 54 | (299) | |||||||||||||||||||
| Stock-based compensation | 15 | 16 | 59 | 86 | |||||||||||||||||||
| Merger-related expense | — | — | — | 7 | |||||||||||||||||||
| Severance expense | 2 | 11 | 12 | 62 | |||||||||||||||||||
| Adjusted EBITDAX | $ | 1,001 | $ | 1,578 | $ | 3,928 | $ | 6,730 | |||||||||||||||
18
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 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 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 to reduce debt in calculating the Net Debt to Adjusted Capitalization ratio.
| (In millions) | December 31, 2023 | December 31, 2022 | |||||||||
| Current portion of long-term debt | $ | 575 | $ | — | |||||||
| Long-term debt, net | 1,586 | 2,181 | |||||||||
| Total debt | $ | 2,161 | $ | 2,181 | |||||||
| Stockholders’ equity | 13,039 | 12,659 | |||||||||
| Total capitalization | $ | 15,200 | $ | 14,840 | |||||||
| Total debt | $ | 2,161 | $ | 2,181 | |||||||
| Less: Cash and cash equivalents | (956) | (673) | |||||||||
| Net debt | $ | 1,205 | $ | 1,508 | |||||||
| Net debt | $ | 1,205 | $ | 1,508 | |||||||
| Stockholders’ equity | 13,039 | 12,659 | |||||||||
| Total adjusted capitalization | $ | 14,244 | $ | 14,167 | |||||||
| Total debt to total capitalization ratio | 14.2 | % | 14.7 | % | |||||||
| Less: Impact of cash and cash equivalents | 5.7 | % | 4.1 | % | |||||||
| Net debt to adjusted capitalization ratio | 8.5 | % | 10.6 | % | |||||||
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) | December 31, 2023 | December 31, 2022 | |||||||||
| Total debt | $ | 2,161 | $ | 2,181 | |||||||
| Net income | 1,625 | $ | 4,065 | ||||||||
| Total debt to net income ratio | 1.3 | x | 0.5 | x | |||||||
| Net debt (as defined above) | $ | 1,205 | $ | 1,508 | |||||||
| Adjusted EBITDAX (Twelve months ended December 31) | 3,928 | 6,730 | |||||||||
| Net debt to Adjusted EBITDAX | 0.3 | x | 0.2 | x | |||||||
19
2024 Guidance
The tables below present full-year and first quarter 2024 guidance.
| Full Year Guidance | ||||||||||||||||||||
| 2023 Guidance | 2023 Actual | 2024 Guidance | ||||||||||||||||||
| Low Mid High | ||||||||||||||||||||
| Total Equivalent Production (MBoed) | 655 - 665 | 667 | 635 - 655 - 675 | |||||||||||||||||
| Gas (Mmcf/day) | 2,840 - 2,870 | 2,884 | 2,650 - 2,725 - 2,800 | |||||||||||||||||
| Oil (MBbl/day) | 94.5 - 95.5 | 96.2 | 99.0 - 102.0 - 105.0 | |||||||||||||||||
| Net wells turned in line | ||||||||||||||||||||
| Marcellus Shale | 65 - 75 | 71 | 37 - 40 - 43 | |||||||||||||||||
| Permian Basin | 85 - 95 | 95 | 75 - 83 - 90 | |||||||||||||||||
| Anadarko Basin | 7-7 | 7 | 20 - 23 - 25 | |||||||||||||||||
| Incurred capital expenditures ($ in millions) | ||||||||||||||||||||
| Total Company | $2,000 - $2,200 | $2,104 | $1,750 - $1,850 - $1,950 | |||||||||||||||||
| Drilling and completion | ||||||||||||||||||||
| Marcellus Shale | $790 - $880 | $834 | $350- $375 -$400 | |||||||||||||||||
| Permian Basin | $880 - $980 | $932 | $945 - $1,000 - $1,055 | |||||||||||||||||
| Anadarko Basin | $160 - $170 | $151 | $270 - $290 - $310 | |||||||||||||||||
| Midstream, saltwater disposal and infrastructure | $170 - $170 | $187 | $185 - $185 - $185 | |||||||||||||||||
| First Quarter Guidance | ||||||||||||||||||||
| Fourth Quarter 2023 Guidance | Fourth Quarter 2023 Actual | First Quarter 2024 Guidance | ||||||||||||||||||
| Low Mid High | ||||||||||||||||||||
| Total Equivalent Production (MBoed) | 645-680 | 697 | 660 - 675 - 690 | |||||||||||||||||
| Gas (Mmcf/day) | 2,780 - 2,900 | 2,970 | 2,850 - 2,900 - 2,950 | |||||||||||||||||
| Oil (MBbl/day) | 98.0 - 102.0 | 104.7 | 95.0 - 97.0 - 99.0 | |||||||||||||||||
| Net wells turned in line | ||||||||||||||||||||
| Marcellus Shale | 8 - 14 | 12 | 20 - 23 - 26 | |||||||||||||||||
| Permian Basin | 20 - 30 | 28 | 15 - 21 - 27 | |||||||||||||||||
| Anadarko Basin | 0 - 0 | 0 | 0 - 0 - 0 | |||||||||||||||||
| Incurred capital expenditures ($ in millions) | ||||||||||||||||||||
| Total Company | $460 - $530 | $457 | $460 - $500 - $540 | |||||||||||||||||
| Drilling and completion | ||||||||||||||||||||
| Marcellus Shale | $175 | |||||||||||||||||||
| Permian Basin | $237 | |||||||||||||||||||
| Anadarko Basin | $15 | |||||||||||||||||||
| Midstream, saltwater disposal and infrastructure | $31 | |||||||||||||||||||
20
Investor Contact
Daniel Guffey - Vice President of Finance, Planning and Investor Relations
281.589.4875
Hannah Stuckey - Investor Relations Manager
281.589.4983
21