News Release
Coterra Energy Reports Fourth-Quarter and Full-Year 2022 Results, Provides 2023 Outlook and Updates Shareholder Return Strategy
HOUSTON, February 22, 2023 - Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported fourth-quarter and full-year 2022 financial and operating results. On October 1, 2021, Coterra announced that the merger involving the Company, which was formerly named Cabot Oil & Gas Corporation (“Cabot”), and Cimarex Energy Co. (“Cimarex”) was completed (the "Merger"). Fourth-quarter 2021 results discussed within this release represent Coterra. Full-year 2021 results include nine months of legacy Cabot results from January 1 to September 30, plus three months of Coterra beginning October 1, unless noted otherwise.
Thomas E. Jorden, Chairman, Chief Executive Officer and President, commented, "Coterra delivered a strong 2022. Outstanding execution led to value creation, outsized shareholder returns and further improvement of our industry-leading balance sheet. Combining our track record of execution with our deep inventory of high-quality assets, Coterra is positioned to succeed through commodity cycles."
Fourth-Quarter 2022 Summary
•Net income for fourth quarter 2022 totaled $1,032 million, or $1.32 per share. Adjusted net income (non-GAAP) for fourth-quarter 2022, excluding non-recurring items, was $905 million, or $1.16 per share.
•Generated cash flow from operating activities of $1,484 million.
•Discretionary cash flow totaled $1,393 million (non-GAAP).
•Accrued capital expenditures totaled $483 million.
•Generated Free Cash Flow of $892 million (non-GAAP).
•Delivered total equivalent production of 632 MBoepd (thousand barrels equivalent per day).
◦Oil production averaged 90.7 MBbls/d (thousand barrels per day), above the high-end of guidance.
◦Natural gas production averaged 2,780 Mmcf/d (million cubic feet per day), above the high-end of guidance.
Coterra's average realized prices for oil, natural gas and natural gas liquids (NGLs) for fourth-quarter 2022, excluding the effect of commodity derivatives, were $82.26 per barrel (Bbl), $4.87 per thousand cubic feet (Mcf), and $25.02 per Bbl, respectively. Including the effect of commodity derivatives, average realized prices for oil and natural gas for fourth-quarter 2022 were $81.57 per Bbl and $4.74 per Mcf, respectively.
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2023 Outlook
"Guided by principles focused on full-cycle value creation and disciplined capital allocation, Coterra expects to invest approximately 50 percent of its cash flow, at recent strip prices", commented Jorden. "This is expected to result in a 2023 production profile that will be relatively flat year-over-year before returning to modest growth in 2024 and 2025. Coterra's dynamic organization, top-tier assets and industry-leading balance sheet are poised to generate long-term consistent profitable growth."
•Estimated cash flow from operating activities of approximately $4.0 billion, at recent commodity strip prices
•Expected capital investment of $2.0 billion to $2.2 billion.
◦$1,825 to $2,025 million is allocated to drilling and completion activities.
◦Approximately 49 percent of drilling and completion capital will be invested in the Permian Basin, 44 percent in the Marcellus Shale and the balance in the Anadarko Basin.
◦Represents approximately 50 percent of projected cash flow from operating activities at recent commodity strip prices.
◦Capital increase driven by inflation (10% y/y) and a modest activity increase.
•Expect annual average production of 610 - 650 MBoe/d, in line with 2022.
◦Expect annual average oil production of 86-92 MBbls/d, up 2% y/y.
◦Expect annual average natural gas production of 2,700 - 2,850 MMcf/d, down modestly y/y as Upper Marcellus delineation increases in 2023 (~40% of 2023 Marcellus activity). The 40% Upper Marcellus weighting is expected to be the high-end over the next few years.
◦Expect to turn-in-line 150 to 175 total net wells.
•Estimate free cash flow (non-GAAP) of approximately $1.9 billion, at recent commodity strip prices.
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.
Increasing Base Dividend, Announcing New Share Repurchase Authorization, Updating Return Strategy
•Coterra's Board of Directors (the "Board") approved a 33 percent increase to the annual base common dividend to $0.80 per share from $0.60 per share.
•After completing its buyback authorization ($1.25 billion) during calendar 2022, the Board approved a new $2.0 billion authorization, representing approximately 11% of the Company's market capitalization as of market close on February 21, 2023. The timing and volume of share repurchases under this authorization will be determined by management, at its discretion. The $2 billion share repurchase program takes effect in February 2023 and does not have a fixed expiration.
•Coterra's 2022 return strategy targeted 50%+ of Free Cash Flow (non-GAAP) paid via cash dividends (base + variable). The company's updated 2023 strategy maintains its 50%+ Free Cash Flow return target but now
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assumes this can be accomplished through a combination of base dividends, share repurchases and/or variable dividends.
Jorden commented, “We are pleased to increase the base dividend, which underscores the confidence in our long-term outlook and financial strength through all cycles. Additionally, we established a new buyback authorization totaling $2.0 billion, which will accelerate returns to shareholders and allow the company to take advantage of value dislocations. We remain committed to returning 50%+ of our Free Cash Flow to shareholders. Due to market conditions and the value proposition of our shares, in 2023 we are realigning our strategy to focus on buybacks ahead of variable dividends. Our 2023 capital return priorities include paying our increased base dividend first, share repurchases second, and variable dividends third. With 2023 estimated Free Cash Flow approaching $2 billion, based on recent strip prices, we are projected to generate sufficient cash flow to fund the base dividend and make meaningful progress on the new buyback authorization.”
Full-Year 2022 and Fourth Quarter 2022 Shareholder Return Highlights
•Driven by relatively high commodity prices and strong execution during 2022, the company returned $3.25 billion to shareholders through our base dividend ($480 million), variable dividend ($1.51 billion) and share repurchases ($1.25 billion). The total 2022 return was 85% of Free Cash Flow and the total dividend (base + variable) was 50% of Free Cash Flow.
•On February 22, 2023, in addition to its base dividend ($0.20 per share), the Board approved a $0.37 per share variable dividend payment based on fourth-quarter 2022 free cash flow (non-GAAP) generation.
◦The approved total quarterly dividend (base plus variable) equals $0.57 per share ($0.20 base, $0.37 variable), and will be paid on March 30, 2023 to holders of record on March 16, 2023.
•During the quarter, the Company repurchased 20 million shares for $510 million, averaging $25.60 per share, to fully execute on its $1.25 billion share repurchase authorization during calendar 2022.
2022 Highlights
•Net Income of $4.1 billion, or $5.09 per share.
•Operating Cash Flow of $5.5 billion, Discretionary Cash Flow of $5.6 billion, Free Cash Flow of $3.9 billion.
•Dividends paid of $2.0 billion, complemented by $1.25 billion of share repurchases.
•Retired $0.9 billion of long-term notes.
•Exceeded initial 2022 production targets as well as emissions reduction targets.
Full-Year 2022 Summary
Full-year 2022 total equivalent production averaged 633.8 MBoepd. Oil production averaged 87.5 MBbls/d and natural gas production averaged 2,806 MMcf/d.
Coterra's average realized prices for oil, natural gas and NGLs for 2022, excluding the effect of commodity derivatives, were $94.47 per Bbl, $5.34 per Mcf, and $33.58 per Bbl, respectively. Including the effect of commodity
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derivatives, average realized prices for oil and natural gas for 2022 were $84.33 per Bbl and $4.91 per Mcf, respectively.
Net income for full-year 2022 totaled $4,065 million or $5.09 per share. Adjusted net income (non-GAAP) for full-year 2022, excluding non-recurring items, was $3,932 million, or $4.94 per share.
Coterra reported cash flow from operating activities of $5,456 million for full-year 2022. Full-year 2022 discretionary cash flow (non-GAAP) was $5,642 million and free cash flow (non-GAAP) totaled $3,942 million, both of which are inclusive of merger-related costs.
Coterra incurred a total of $1,737 million of capital expenditures in full-year 2022, including $1,617 million of drilling and completion capital.
The company achieved zero routine high-pressure flaring across Coterra's three core operating regions during 2022. Additionally, the company beat its 2022 environmental goals and laid out ambitious 2023 goals.
Strong Financial Position
As of December 31, 2022, Coterra had total long-term debt of $2.2 billion with a principal amount of $2.1 billion, with no substantial maturities until 2024. The Company exited the year with a cash balance of $0.7 billion and no debt outstanding under its revolving credit facility. Coterra's net debt to trailing twelve month EBITDAX ratio (non-GAAP) at December 31, 2022 was 0.2x.
2022 Proved Reserves
At December 31, 2022, Coterra's proved reserves totaled 2,399 MMBoe, down 17 percent from the Company's proved reserves of 2,893 MMBoe at December 31, 2021, which is in line with estimates provided in the Company's third-quarter 2022 earnings press release. At year-end 2022, proved undeveloped reserves accounted for 24 percent of total proved reserves, down from 26 percent at year-end 2021. The Company's proved reserves are approximately 78 percent natural gas, 10 percent oil and 12 percent NGLs. Proved developed reserves totaled 1,817 MMBoe, or 76 percent of total proved reserves. For a summary of Coterra's estimated proved reserves at December 31, 2022, see the "Year-End Proved Reserves" table below.
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 "A Sustainable Future" on www.coterra.com.
Conference Call
Coterra will host a conference call tomorrow, Thursday, February 23, 2023, at 9:00 AM CT (10:00 AM ET), to discuss fourth-quarter and full-year 2022 financial and operating results and its 2023 outlook.
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Conference Call Information
Date: Thursday, February 23, 2023
Time: 10:00 AM ET / 9:00 AM CT
Dial-in (for callers in the U.S. and Canada): (888) 550-5424
Int'l 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 producer, delivering returns with a commitment to sustainability leadership. 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, future financial and operating performance and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals 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" 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 risk that the recently combined businesses will not integrate successfully; the risk that the cost savings and any other synergies may not be fully realized or may take longer to realize than expected; the volatility in commodity prices for crude oil and natural gas; the effect of future regulatory or legislative actions, including the risk of new restrictions with respect to well spacing, hydraulic fracturing, natural gas flaring, seismicity, produced water disposal, or other oil and natural gas development activities; disruption from the transaction making it more difficult to maintain relationships with customers, employees or suppliers; the diversion of management time on integration-related issues; the continuing effects of the COVID-19 pandemic and the impact thereof 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; 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 of directors. While the list of factors presented here is considered representative, no such list should be considered to be a complete statement of
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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 and Cimarex’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 and on the SEC’s website at www.sec.gov.
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, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| PRODUCTION VOLUMES | |||||||||||||||||||||||
| Marcellus Shale | |||||||||||||||||||||||
| Natural gas (Bcf) | 197.2 | 229.4 | 804.6 | 853.0 | |||||||||||||||||||
| Equivalent production (MMBoe) | 32.9 | 38.0 | 134.1 | 142.0 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 357.2 | 415.5 | 367.4 | 389.5 | |||||||||||||||||||
| Permian Basin | |||||||||||||||||||||||
| Natural gas (Bcf) | 40.7 | 41.3 | 154.9 | 41.3 | |||||||||||||||||||
| Oil (MMBbl) | 7.6 | 7.4 | 29.6 | 7.4 | |||||||||||||||||||
| NGL (MMBbl) | 5.3 | 5.1 | 21.7 | 5.1 | |||||||||||||||||||
| Equivalent production (MMBoe) | 19.7 | 19.5 | 77.2 | 19.5 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 214.3 | 211.5 | 211.4 | 211.5 | |||||||||||||||||||
| Anadarko Basin | |||||||||||||||||||||||
| Natural gas (Bcf) | 17.8 | 16.5 | 64.3 | 16.5 | |||||||||||||||||||
| Oil (MMBbl) | 0.7 | 0.7 | 2.3 | 0.7 | |||||||||||||||||||
| NGL (MMBbl) | 1.9 | 2.0 | 6.9 | 2.0 | |||||||||||||||||||
| Equivalent production (MMBoe) | 5.5 | 5.4 | 19.9 | 5.4 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 60.2 | 58.7 | 54.6 | 58.7 | |||||||||||||||||||
Total Company(1) | |||||||||||||||||||||||
| Natural gas (Bcf) | 255.8 | 287.3 | 1,024.3 | 911.1 | |||||||||||||||||||
| Oil (MMBbl) | 8.3 | 8.1 | 31.9 | 8.1 | |||||||||||||||||||
| NGL (MMBbl) | 7.2 | 7.1 | 28.7 | 7.1 | |||||||||||||||||||
| Equivalent production (MMBoe) | 58.2 | 63.1 | 231.3 | 167.1 | |||||||||||||||||||
| Daily equivalent production (MBoepd) | 632.2 | 686.2 | 633.8 | 660.0 | |||||||||||||||||||
| AVERAGE SALES PRICE (excluding hedges) | |||||||||||||||||||||||
| Marcellus Shale | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 5.16 | $ | 4.43 | $ | 5.29 | $ | 2.98 | |||||||||||||||
| Permian Basin | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 3.22 | $ | 4.13 | $ | 5.18 | $ | 4.13 | |||||||||||||||
| Oil ($/Bbl) | $ | 82.27 | $ | 75.53 | $ | 94.55 | $ | 75.53 | |||||||||||||||
| NGL ($/Bbl) | $ | 23.40 | $ | 33.25 | $ | 32.59 | $ | 33.25 | |||||||||||||||
| Anadarko Basin | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 5.44 | $ | 5.19 | $ | 6.29 | $ | 5.19 | |||||||||||||||
| Oil ($/Bbl) | $ | 81.94 | $ | 76.49 | $ | 93.34 | $ | 76.49 | |||||||||||||||
| NGL ($/Bbl) | $ | 29.60 | $ | 36.61 | $ | 36.66 | $ | 36.61 | |||||||||||||||
| Total Company | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 4.87 | $ | 4.43 | $ | 5.34 | $ | 3.07 | |||||||||||||||
| Oil ($/Bbl) | $ | 82.26 | $ | 75.61 | $ | 94.47 | $ | 75.61 | |||||||||||||||
| NGL ($/Bbl) | $ | 25.02 | $ | 34.18 | $ | 33.58 | $ | 34.18 | |||||||||||||||
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| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| AVERAGE SALES PRICE (including hedges) | |||||||||||||||||||||||
| Total Company | |||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 4.74 | $ | 3.57 | $ | 4.91 | $ | 2.73 | |||||||||||||||
| Oil ($/Bbl) | $ | 81.57 | $ | 60.35 | $ | 84.33 | $ | 60.35 | |||||||||||||||
| NGL ($/Bbl) | $ | 25.02 | $ | 34.18 | $ | 33.58 | $ | 34.18 | |||||||||||||||
| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
WELLS DRILLED(2) | |||||||||||||||||||||||
| Gross wells | |||||||||||||||||||||||
| Marcellus Shale | 27 | 22 | 93 | 95 | |||||||||||||||||||
| Permian Basin | 43 | 19 | 161 | 19 | |||||||||||||||||||
| Anadarko Basin | 9 | — | 31 | — | |||||||||||||||||||
| 79 | 41 | 285 | 114 | ||||||||||||||||||||
| Net wells | |||||||||||||||||||||||
| Marcellus Shale | 27.0 | 19.1 | 93.0 | 89.2 | |||||||||||||||||||
| Permian Basin | 13.7 | 10.7 | 72.7 | 10.7 | |||||||||||||||||||
| Anadarko Basin | 0.1 | — | 8.9 | — | |||||||||||||||||||
| 40.8 | 29.8 | 174.6 | 99.9 | ||||||||||||||||||||
WELLS COMPLETED(2) | |||||||||||||||||||||||
| Gross wells | |||||||||||||||||||||||
| Marcellus Shale | 19 | 21 | 81 | 92 | |||||||||||||||||||
| Permian Basin | 53 | 36 | 144 | 36 | |||||||||||||||||||
| Anadarko Basin | 11 | 4 | 26 | 4 | |||||||||||||||||||
| 83 | 61 | 251 | 132 | ||||||||||||||||||||
| Net wells | |||||||||||||||||||||||
| Marcellus Shale | 19.0 | 21.0 | 78.0 | 88.1 | |||||||||||||||||||
| Permian Basin | 22.2 | 20.2 | 64.5 | 20.2 | |||||||||||||||||||
| Anadarko Basin | 5.9 | — | 8.7 | — | |||||||||||||||||||
| 47.1 | 41.2 | 151.2 | 108.3 | ||||||||||||||||||||
| TURN IN LINES | |||||||||||||||||||||||
| Gross wells | |||||||||||||||||||||||
| Marcellus Shale | 26 | 22 | 81 | 92 | |||||||||||||||||||
| Permian Basin | 39 | 33 | 144 | 33 | |||||||||||||||||||
| Anadarko Basin | 11 | 4 | 26 | 4 | |||||||||||||||||||
| 76 | 59 | 251 | 129 | ||||||||||||||||||||
| Net wells | |||||||||||||||||||||||
| Marcellus Shale | 26.0 | 22.0 | 78.1 | 88.1 | |||||||||||||||||||
| Permian Basin | 13.5 | 18.5 | 61.3 | 18.5 | |||||||||||||||||||
| Anadarko Basin | 5.9 | — | 8.7 | — | |||||||||||||||||||
| 45.4 | 40.5 | 148.1 | 106.6 | ||||||||||||||||||||
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| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
AVERAGE UNIT COSTS ($/Boe)(3) | |||||||||||||||||||||||
| Direct operations | $ | 2.17 | $ | 1.62 | $ | 1.99 | $ | 0.93 | |||||||||||||||
| Transportation, processing and gathering | 3.94 | 3.87 | 4.13 | 3.97 | |||||||||||||||||||
| Taxes other than income | 1.55 | 1.05 | 1.58 | 0.50 | |||||||||||||||||||
| Exploration | 0.11 | 0.14 | 0.13 | 0.11 | |||||||||||||||||||
| Depreciation, depletion and amortization | 7.54 | 6.49 | 7.07 | 4.15 | |||||||||||||||||||
General and administrative (excluding stock-based compensation and merger-related expense)(4) | 1.17 | 1.52 | 1.03 | 0.84 | |||||||||||||||||||
| Stock-based compensation | 0.28 | 0.49 | 0.37 | 0.34 | |||||||||||||||||||
| Merger-related expense | 0.18 | 0.41 | 0.30 | 0.43 | |||||||||||||||||||
| Interest expense | 0.17 | 0.38 | 0.30 | 0.37 | |||||||||||||||||||
| $ | 17.11 | $ | 15.97 | $ | 16.90 | $ | 11.64 | ||||||||||||||||
_______________________________________________________________________________
(1)Production for the twelve months ended December 31, 2021 does not include legacy Cimarex production from January 1, 2021 to September 30, 2021. Combined Coterra and legacy Cimarex full-year 2021 natural gas, oil and NGL production totaled 1,068 Bcf, 28.4 MMBbl, and 25.1 MMBbl, respectively, or total equivalent production of 231.6 MMBoe, or 634 MBoepd.
(2)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.
(3)Total unit costs may differ from the sum of the individual costs due to rounding.
(4)Includes the impact of severance expense related to accrued severance costs as a result of the Merger and the Company's 2021 Early Retirement Program.
Variable Dividend Calculation
| (In millions) | Twelve Months Ended December 31, 2022 | |||||||||||||
Free cash flow(1) | $ | 3,942 | ||||||||||||
| 50% payout (Board Discretion: 50% plus) | 50 | % | ||||||||||||
| Annual return to shareholders | 1,971 | |||||||||||||
| Annual base dividend ($0.15 per share for the first three quarters and $0.20 per share for the fourth quarter) | 512 | |||||||||||||
Variable cash dividend(2) | $ | 1,459 | ||||||||||||
_______________________________________________________________________________
(1)See "Supplemental non-GAAP Financial Measures" below for a description of free cash flow as well as reconciliations of this measures to discretionary cash flow and cash flow from operating activities.
(2)Total cash amounts paid are subject to change based on the number of shares of issued common stock on the dividend record date.
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Derivatives Information
As of December 31, 2022, the Company had the following outstanding financial commodity derivatives:
| 2023 | ||||||||||||||||||||||||||
| Natural Gas | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||
| Waha gas collars | ||||||||||||||||||||||||||
| Volume (MMBtu) | 8,100,000 | 8,190,000 | 8,280,000 | 8,280,000 | ||||||||||||||||||||||
Weighted average floor ($/MMBtu) | $ | 3.03 | $ | 3.03 | $ | 3.03 | $ | 3.03 | ||||||||||||||||||
Weighted average ceiling ($/MMBtu) | $ | 5.39 | $ | 5.39 | $ | 5.39 | $ | 5.39 | ||||||||||||||||||
| NYMEX collars | ||||||||||||||||||||||||||
| Volume (MMBtu) | 54,000,000 | 31,850,000 | 32,200,000 | 29,150,000 | ||||||||||||||||||||||
Weighted average floor ($/MMBtu) | $ | 5.12 | $ | 4.07 | $ | 4.07 | $ | 4.03 | ||||||||||||||||||
Weighted average ceiling ($/MMBtu) | $ | 9.34 | $ | 6.78 | $ | 6.78 | $ | 6.61 | ||||||||||||||||||
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| 2023 | ||||||||||||||
| Oil | First Quarter | Second Quarter | ||||||||||||
| WTI oil collars | ||||||||||||||
| Volume (MBbl) | 1,350 | 1,365 | ||||||||||||
| Weighted average floor ($/Bbl) | $ | 70.00 | $ | 70.00 | ||||||||||
| Weighted average ceiling ($/Bbl) | $ | 116.03 | $ | 116.03 | ||||||||||
| WTI Midland oil basis swaps | ||||||||||||||
| Volume (MBbl) | 1,350 | 1,365 | ||||||||||||
| Weighted average differential ($/Bbl) | $ | 0.63 | $ | 0.63 | ||||||||||
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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, 2022.
| Oil (MBbl) | Natural Gas (Bcf) | NGL (MBbl) | Total (MBOE) | ||||||||||||||||||||
| PROVED RESERVES | |||||||||||||||||||||||
| December 31, 2021 | 189,429 | 14,895 | 220,615 | 2,892,582 | |||||||||||||||||||
| Revision of previous estimates | 14,594 | (4,299) | 35,162 | (666,716) | |||||||||||||||||||
| Extensions and discoveries | 69,118 | 1,602 | 69,862 | 405,972 | |||||||||||||||||||
| Purchases of reserves | — | — | — | — | |||||||||||||||||||
| Production | (31,926) | (1,024) | (28,697) | (231,342) | |||||||||||||||||||
| Sales of reserves | (1,460) | (1) | (177) | (1,830) | |||||||||||||||||||
| December 31, 2022 | 239,755 | 11,173 | 296,765 | 2,398,666 | |||||||||||||||||||
| PROVED DEVELOPED RESERVES | |||||||||||||||||||||||
| December 31, 2021 | 153,010 | 10,691 | 193,598 | 2,128,439 | |||||||||||||||||||
| December 31, 2022 | 168,649 | 8,543 | 224,706 | 1,817,140 | |||||||||||||||||||
| PROVED RESERVES BY REGION | |||||||||||||||||||||||
| Marcellus Shale | 8 | 8,989 | — | 1,498,181 | |||||||||||||||||||
| Permian Basin | 221,436 | 1,505 | 218,702 | 691,028 | |||||||||||||||||||
| Anadarko Basin | 18,051 | 676 | 77,834 | 208,545 | |||||||||||||||||||
| Other | 261 | 3 | 229 | 912 | |||||||||||||||||||
| 239,756 | 11,173 | 296,765 | 2,398,666 | ||||||||||||||||||||
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CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| (In millions, except per share amounts) | 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||
| OPERATING REVENUES | |||||||||||||||||||||||
| Natural gas | $ | 1,246 | $ | 1,272 | $ | 5,469 | $ | 2,798 | |||||||||||||||
| Oil | 686 | 616 | 3,016 | 616 | |||||||||||||||||||
| NGL | 180 | 243 | 964 | 243 | |||||||||||||||||||
| Gain (loss) on derivative instruments | 150 | 81 | (463) | (221) | |||||||||||||||||||
| Other | 18 | 13 | 65 | 13 | |||||||||||||||||||
| 2,280 | 2,225 | 9,051 | 3,449 | ||||||||||||||||||||
| OPERATING EXPENSES | |||||||||||||||||||||||
| Direct operations | 126 | 102 | 460 | 156 | |||||||||||||||||||
| Transportation, processing and gathering | 229 | 244 | 955 | 663 | |||||||||||||||||||
| Taxes other than income | 90 | 66 | 366 | 83 | |||||||||||||||||||
| Exploration | 6 | 9 | 29 | 18 | |||||||||||||||||||
| Depreciation, depletion and amortization | 439 | 410 | 1,635 | 693 | |||||||||||||||||||
General and administrative (excluding stock-based compensation and merger-related costs)(1) | 68 | 96 | 241 | 141 | |||||||||||||||||||
Stock-based compensation(2) | 16 | 31 | 86 | 57 | |||||||||||||||||||
| Merger-related expense | 11 | 26 | 69 | 72 | |||||||||||||||||||
| 985 | 984 | 3,841 | 1,883 | ||||||||||||||||||||
| Loss on sale of assets | — | (2) | (1) | (2) | |||||||||||||||||||
| INCOME FROM OPERATIONS | 1,295 | 1,239 | 5,209 | 1,564 | |||||||||||||||||||
| Interest expense, net | 11 | 24 | 70 | 62 | |||||||||||||||||||
| Gain on debt extinguishment | (2) | — | (28) | — | |||||||||||||||||||
| Other expense | (2) | — | (2) | — | |||||||||||||||||||
| Income before income taxes | 1,288 | 1,215 | 5,169 | 1,502 | |||||||||||||||||||
| Income tax expense | 256 | 276 | 1,104 | 344 | |||||||||||||||||||
| NET INCOME | $ | 1,032 | $ | 939 | $ | 4,065 | $ | 1,158 | |||||||||||||||
| Earnings per share - Basic | $ | 1.32 | $ | 1.16 | $ | 5.09 | $ | 2.30 | |||||||||||||||
| Weighted-average common shares outstanding | 781 | 810 | 796 | 503 | |||||||||||||||||||
(1)For the three and twelve months ended December 31, 2022, includes severance expense of $11 million and $62 million, respectively, related to accrued severance costs as a result of the Merger. For the three months ended December 31, 2021, includes severance expense of $44 million related to accrued severance costs as a result of the Merger. For the twelve months ended December 31, 2021, includes severance expense of $44 million related to accrued severance costs as a result of the Merger and $2 million related to early retirements under the Company's 2021 Early Retirement Program.
(2)Includes the impact of our performance share awards and restricted stock.
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CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
| (In millions) | December 31, 2022 | December 31, 2021 | |||||||||
| ASSETS | |||||||||||
| Current assets | $ | 2,211 | $ | 2,136 | |||||||
| Properties and equipment, net (successful efforts method) | 17,479 | 17,375 | |||||||||
| Other assets | 464 | 389 | |||||||||
| $ | 20,154 | $ | 19,900 | ||||||||
| LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | |||||||||||
| Current liabilities | $ | 1,193 | $ | 1,220 | |||||||
| Long-term debt, net (excluding current maturities) | 2,181 | 3,125 | |||||||||
| Deferred income taxes | 3,339 | 3,101 | |||||||||
| Other long term liabilities | 771 | 666 | |||||||||
| Cimarex redeemable preferred stock | 11 | 50 | |||||||||
| Stockholders’ equity | 12,659 | 11,738 | |||||||||
| $ | 20,154 | $ | 19,900 | ||||||||
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CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
| Quarter Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| (In millions) | 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||||||||
| Net income | $ | 1,032 | $ | 939 | $ | 4,065 | $ | 1,158 | |||||||||||||||
| Depreciation, depletion and amortization | 439 | 410 | 1,635 | 693 | |||||||||||||||||||
| Deferred income tax expense | 107 | 109 | 235 | 126 | |||||||||||||||||||
| Loss on sale of assets | — | 2 | 1 | 2 | |||||||||||||||||||
| (Gain) loss on derivative instruments | (150) | (81) | 463 | 221 | |||||||||||||||||||
| Net cash paid in settlement of derivative instruments | (39) | (370) | (762) | (431) | |||||||||||||||||||
| Stock-based compensation and other | 11 | 29 | 73 | 52 | |||||||||||||||||||
| Income charges not requiring cash | (7) | (12) | (68) | (10) | |||||||||||||||||||
| Changes in assets and liabilities | 91 | (73) | (186) | (144) | |||||||||||||||||||
| Net cash provided by operating activities | 1,484 | 953 | 5,456 | 1,667 | |||||||||||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||||||||||||||
| Capital expenditures for drilling, completion and other fixed asset additions | (501) | (267) | (1,700) | (723) | |||||||||||||||||||
| Capital expenditures for leasehold and property acquisitions | (4) | (1) | (10) | (5) | |||||||||||||||||||
| Proceeds from sale of assets | 14 | 8 | 36 | 8 | |||||||||||||||||||
| Cash received from Merger | — | 1,033 | — | 1,033 | |||||||||||||||||||
| Net cash (used in) provided by investing activities | (491) | 773 | (1,674) | 313 | |||||||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||||||||||||||
| Net borrowings (repayments) of debt | (44) | — | (874) | (188) | |||||||||||||||||||
| Repayment of finance leases | (2) | (2) | (6) | (2) | |||||||||||||||||||
| Common stock repurchases | (510) | — | (1,250) | — | |||||||||||||||||||
| Dividends paid | (533) | (652) | (1,992) | (780) | |||||||||||||||||||
| Tax withholding on vesting of stock awards | (10) | (109) | (25) | (114) | |||||||||||||||||||
| Capitalized debt issuance costs | — | (4) | — | (4) | |||||||||||||||||||
| Cash received for stock option exercises | 1 | 2 | 12 | 2 | |||||||||||||||||||
| Cash paid for conversion of redeemable preferred stock | — | — | (10) | — | |||||||||||||||||||
| Net cash used in financing activities | (1,098) | (765) | (4,145) | (1,086) | |||||||||||||||||||
| Net (decrease) increase in cash, cash equivalents and restricted cash | $ | (105) | $ | 961 | $ | (363) | $ | 894 | |||||||||||||||
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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 future impairments and future changes in capital. 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.
Present Value of Investment (PVI10) is often used by management as a return-on-investment metric and defined as the estimated net present value (using a 10% discount rate) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs), adding back our direct net costs incurred in drilling and adding back our completing, constructing facilities, and flowing back such wells, and then dividing that sum by our direct net costs incurred in drilling, completing, constructing facilities, and flowing back such wells.
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) | 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||
| As reported - net income | $ | 1,032 | $ | 939 | $ | 4,065 | $ | 1,158 | |||||||||||||||
| Reversal of selected items: | |||||||||||||||||||||||
| Loss on sale of assets | — | 2 | 1 | 2 | |||||||||||||||||||
Loss (gain) on derivative instruments(1) | (189) | (451) | (299) | (210) | |||||||||||||||||||
| Gain on debt extinguishment | (2) | — | (28) | — | |||||||||||||||||||
| Stock-based compensation expense | 16 | 31 | 86 | 57 | |||||||||||||||||||
| Severance expense | 11 | 44 | 62 | 46 | |||||||||||||||||||
| Merger-related expense | — | 26 | 7 | 72 | |||||||||||||||||||
| Tax effect on selected items | 37 | 79 | 38 | 7 | |||||||||||||||||||
| Adjusted net income | $ | 905 | $ | 670 | $ | 3,932 | $ | 1,132 | |||||||||||||||
| As reported - earnings per share | $ | 1.32 | $ | 1.16 | $ | 5.09 | $ | 2.30 | |||||||||||||||
| Per share impact of selected items | (0.16) | (0.33) | (0.15) | (0.05) | |||||||||||||||||||
| Adjusted earnings per share | $ | 1.16 | $ | 0.83 | $ | 4.94 | $ | 2.25 | |||||||||||||||
| Weighted-average common shares outstanding | 781 | 810 | 796 | 503 | |||||||||||||||||||
_______________________________________________________________________________
(1)This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in (Loss) gain on derivative instruments in the Condensed Consolidated Statement of Operations.
15
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) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| Cash flow from operating activities | $ | 1,484 | $ | 953 | $ | 5,456 | $ | 1,667 | ||||||||||||||||||
| Changes in assets and liabilities | (91) | 73 | 186 | 144 | ||||||||||||||||||||||
| Discretionary cash flow | 1,393 | 1,026 | 5,642 | 1,811 | ||||||||||||||||||||||
| Cash paid for capital expenditures for drilling, completion and other fixed asset additions | (501) | (267) | (1,700) | (723) | ||||||||||||||||||||||
| Free cash flow | $ | 892 | $ | 759 | $ | 3,942 | $ | 1,088 | ||||||||||||||||||
Capital Expenditures
| Quarter Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||||
| (In millions) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| Capital expenditures for drilling, completion and other fixed asset additions | $ | 501 | $ | 267 | $ | 1,700 | $ | 723 | ||||||||||||||||||
| Capital expenditures for leasehold and property acquisitions | 4 | 1 | 10 | 5 | ||||||||||||||||||||||
| Change in accrued capital costs | (22) | (4) | 27 | (3) | ||||||||||||||||||||||
| Capital expenditures | $ | 483 | $ | 264 | $ | 1,737 | $ | 725 | ||||||||||||||||||
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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) | 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||
| Net income | $ | 1,032 | $ | 939 | $ | 4,065 | $ | 1,158 | |||||||||||||||
| Plus (less): | |||||||||||||||||||||||
| Interest expense, net | 11 | 24 | 70 | 62 | |||||||||||||||||||
| Gain on debt extinguishment | (2) | — | (28) | — | |||||||||||||||||||
| Other expense | (2) | — | (2) | — | |||||||||||||||||||
| Income tax expense | 256 | 276 | 1,104 | 344 | |||||||||||||||||||
| Depreciation, depletion and amortization | 439 | 410 | 1,635 | 693 | |||||||||||||||||||
| Exploration | 6 | 9 | 29 | 18 | |||||||||||||||||||
| Loss on sale of assets | — | 2 | 1 | 2 | |||||||||||||||||||
| Non-cash (gain) loss on derivative instruments | (189) | (451) | (299) | (210) | |||||||||||||||||||
| Stock-based compensation | 16 | 31 | 86 | 57 | |||||||||||||||||||
| Merger-related expense | — | 26 | 7 | 72 | |||||||||||||||||||
| Severance expense | 11 | 44 | 62 | 46 | |||||||||||||||||||
| Adjusted EBITDAX | $ | 1,578 | $ | 1,310 | $ | 6,730 | $ | 2,242 | |||||||||||||||
| Cimarex Adjusted EBITDAX (nine months ended September 30, 2021) | — | — | — | 1,005 | |||||||||||||||||||
| Combined Adjusted EBITDAX | $ | 1,578 | $ | 1,310 | $ | 6,730 | $ | 3,247 | |||||||||||||||
17
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, 2022 | December 31, 2021 | |||||||||
| Current portion of long-term debt | $ | — | $ | — | |||||||
| Long-term debt, net | 2,181 | 3,125 | |||||||||
| Total debt | $ | 2,181 | $ | 3,125 | |||||||
| Stockholders’ equity | 12,659 | 11,738 | |||||||||
| Total capitalization | $ | 14,840 | $ | 14,863 | |||||||
| Total debt | $ | 2,181 | $ | 3,125 | |||||||
| Less: Cash and cash equivalents | (673) | (1,036) | |||||||||
| Net debt | $ | 1,508 | $ | 2,089 | |||||||
| Net debt | $ | 1,508 | $ | 2,089 | |||||||
| Stockholders’ equity | 12,659 | 11,738 | |||||||||
| Total adjusted capitalization | $ | 14,167 | $ | 13,827 | |||||||
| Total debt to total capitalization ratio | 14.7 | % | 21.0 | % | |||||||
| Less: Impact of cash and cash equivalents | 4.1 | % | 5.9 | % | |||||||
| Net debt to adjusted capitalization ratio | 10.6 | % | 15.1 | % | |||||||
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, 2022 | December 31, 2021 | |||||||||
| Total debt | $ | 2,181 | $ | 3,125 | |||||||
| Net income | 4,065 | $ | 1,158 | ||||||||
| Total debt to net income ratio | 0.5 | x | 2.7 | x | |||||||
| Net debt (as defined above) | $ | 1,508 | $ | 2,089 | |||||||
| Adjusted EBITDAX (Twelve months ended December 31) | 6,730 | 2,242 | |||||||||
| Net debt to Adjusted EBITDAX | 0.2 | x | 0.9 | x | |||||||
18
Reconciliation of Net Debt to EBITDAX - Combined
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 EBITDAX for that purpose. 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.
The EBITDAX used in the calculation below is reflective of nine months of legacy Cabot and Cimarex EBITDAX, plus three months of Coterra EBITDAX. Legacy Cimarex operated under the full cost accounting method, unlike legacy Cabot, now Coterra, which operates under the successful efforts accounting method. This difference in accounting methodologies leads to differences in the calculation of company financials and the figures below should not be relied on to predict future performance of the combined business, which operates under the successful efforts accounting method.
| (In millions) | December 31, 2021 | ||||
| Net debt | $ | 2,089 | |||
| EBITDAX (Twelve months ended December 31) | 3,201 | ||||
| Net debt to EBITDAX | 0.6 | x | |||
19
Investor Contact
Daniel Guffey - Vice President of Finance, Planning & Analysis and Investor Relations
281.589.4875
Hannah Stuckey - Investor Relations Manager
281.589.4983
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