Coterra Energy Reports Fourth-Quarter and Full-Year 2021 Results, Provides 2022 Outlook and Updates Shareholder Return Strategy
Coterra Energy Inc. (NYSE: CTRA) reported robust financial results for Q4 and full-year 2021. Q4 net income reached $939 million, or $1.16 per share, while total cash flow from operations was $953 million. The company increased its annual base dividend by 20% to $0.60 per share and declared a supplemental variable dividend of $0.41 per share. Coterra's long-term debt stood at $3.1 billion, with a cash balance of $1 billion. The company plans to invest $1.4 to $1.5 billion in 2022, anticipating free cash flow of $3 billion and an overall production guidance decrease of 3% from 2021 levels.
- Q4 2021 net income of $939 million, or $1.16 per share.
- Annual base dividend increased by 20% to $0.60 per share.
- Supplemental variable dividend of $0.41 per share declared.
- Generated cash flow from operating activities of $953 million in Q4 2021.
- Forecasting free cash flow of approximately $3 billion for 2022.
- Expecting a 3% decline in total equivalent production in 2022 compared to 2021 levels.
HOUSTON, Feb. 23, 2022 /PRNewswire/ -- Coterra Energy Inc. (NYSE: CTRA) ("Coterra" or the "Company") today reported fourth-quarter and full-year 2021 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.
Net income for fourth-quarter 2021 totaled
Fourth-Quarter 2021 Highlights
- Generated cash flow from operating activities of
$953 million . - Discretionary cash flow totaled
$1,026 million (non-GAAP). - Generated free cash flow of
$758 million (non-GAAP). - Delivered total equivalent production of 686 MBoepd.
- Oil production averaged 88.6 MBopd and natural gas production averaged 3,123 MMcfpd.
- Exited the year with zero routine high-pressure flaring across Coterra's three core operating regions.
Shareholder Return Highlights
- On February 23, 2022, Coterra's Board of Directors (the "Board") approved a 20 percent increase to the annual base common dividend from
$0.50 per share to$0.60 per share ($0.15 per share, per quarter). - On February 23, 2022, the Board also approved an incremental
$0.41 per share variable dividend payment based on fourth-quarter 2021 free cash flow (non-GAAP) generation. - The approved base plus variable quarterly dividend equals
$0.56 per share ($0.15 base,$0.41 variable), and will be paid on March 17, 2022 to holders of record on March 7, 2022. - Base plus variable quarterly dividend payment represents a return of 48 percent of cash flow from operating activities or, 60 percent of free cash flow (non-GAAP).
- Separately, the Company announced a share repurchase program of its common stock with a
$1.25 billion authorization, representing approximately 7 percent of the Company's market capitalization as of market close on February 22, 2022.
2022 Outlook
- Total capital investment in 2022 expected to be between
$1,400 and$1,500 million , with approximately 88 percent allocated towards drilling and completion operations. - 2022 capital investment is less than 35 percent of projected cash flow from operating activities at recent strip prices.
- Projecting 2022 free cash flow (non-GAAP) of approximately
$3 billion at recent strip prices. - Guiding to combined company 4 and 10 percent annual oil volume growth and approximately 3 percent total equivalent production decline.
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.
Thomas E. Jorden, Chief Executive Officer and President, commented, "Coterra's initial quarter as a combined company generated solid results and we are excited to communicate our 2022 plans. We look to remain disciplined in 2022, with plans to reinvest less than 35 percent of our projected cash flow from operating activities, at the recent strip. While all three regions provide ample and competitive opportunities for investment, in light of inflation, service availability and prevailing commodity prices, we made a tactical decision to allocate incremental capital toward our oil assets. This decision was driven by our focus on optimizing free cash flow generation and returns to shareholders, with the added benefit of providing a more balanced revenue profile between liquids and natural gas."
"Today we also proudly announce the next phase of our shareholder return strategy, both by increasing our base common dividend and initiating a
Fourth-Quarter 2021 Summary
Fourth-quarter 2021 total equivalent production averaged 686 thousand barrels of oil equivalent per day (MBoepd). Oil production averaged 88.6 thousand barrels per day (MBopd) in the fourth quarter and natural gas production averaged 3,123 million cubic feet per day (MMcfpd).
Coterra's average realized prices for oil, natural gas and natural gas liquids (NGLs) for fourth-quarter 2021, excluding the effect of commodity derivatives, were
Generated Strong Cash Flow
For fourth-quarter 2021, Coterra reported cash flow from operating activities of
Coterra incurred a total of
Full-Year 2021 Summary
Full-year 2021 total equivalent production averaged 457.8 MBoepd. Oil production averaged 22.3 MBopd and natural gas production averaged 2,496 MMcfpd. Combined full-year 2021 total equivalent production averaged 634 MBoepd, including average oil production of 77.9 MBopd and natural gas production of 2,927 MMcfpd.
Coterra's average realized prices for oil, natural gas and NGLs for 2021, excluding the effect of commodity derivatives, were
Coterra reported cash flow from operating activities of
Coterra incurred a total of
Strong Financial Position
As of December 31, 2021, Coterra had total long-term debt of
2021 Proved Reserves
At December 31, 2021, Coterra's proved reserves totaled 2,893 MMBoe, up 27 percent from the Company's proved reserves of 2,279 MMBoe at December 31, 2020, which is primarily driven by the Merger. The Company's proved reserves are approximately 86 percent natural gas, 6 percent oil and 8 percent NGLs. Proved developed reserves totaled 2,128 MMBoe, or 74 percent of the total proved reserves. Coterra's proved reserves at December 31, 2021 represent a 3 percent increase to the combined reserves of legacy Cabot and Cimarex, which totaled 2,813 MMBoe at December 31, 2020. The increase to proved reserves at year-end 2021 compared to the combined proved reserves at year-end 2020 is primarily attributed to the addition of new proved developed producing wells. For a summary of Coterra's estimated proved reserves at December 31, 2021, see the "Year-End Proved Reserves" table below.
Outlook
Coterra plans to invest
In 2022, total equivalent production is expected to average between 600 and 635 MBoepd, down 3 percent at the midpoint from combined Coterra and legacy Cimarex 2021 production of 634 MBoepd. Oil production for the year is expected to be 81 to 86 MBopd, up 4 to 10 percent from combined Coterra and legacy Cimarex full-year 2021 volumes. Full-year natural gas production is projected to be 2,680 to 2,850 MMcfpd. First-quarter 2022 total equivalent production is expected to average between 610 to 630 MBoepd, including natural gas volumes between 2,775 and 2,850 MMcfpd and oil production of 79 to 82 MBopd.
Increasing Returns to Shareholders
On February 23, 2022, Coterra's Board approved a 20 percent increase to the annual base common dividend from
Based on fourth-quarter 2021 free cash flow (non-GAAP), Coterra's Board today declared a quarterly base plus variable dividend of
The Company also announced today the next step in its shareholder return strategy, initiating a supplementary share repurchase program with a
The timing and volume of share repurchases under this authorization will be determined by management, at its discretion. Management expects its share repurchase program to be driven by relative and intrinsic value opportunities. The share repurchase program is in excess of the Company's base plus variable dividend strategy and our first priority remains funding and growing a sustainable base dividend.
Committed to Sustainability and ESG Leadership
Coterra is committed to environmental stewardship, sustainable practices, and strong corporate governance. Coterra has published combined environmental and safety metrics for 2019 and 2020 related to legacy Cabot and Cimarex operations, which can be accessed on the "Our Performance" page under the "A Sustainable Future" section of the Company's website at www.coterra.com. The Company is committed to publishing a sustainability report aligned with SASB and TCFD reporting standards and expects to publish its inaugural report in fourth-quarter 2022.
Preliminary results for 2021 include:
15% reduction in greenhouse gas emissions intensity,48% reduction in methane emissions intensity,50% reduction in Permian Basin high-pressure flaring intensity, and- Zero routine high-pressure flaring across all three operating regions by year-end.
Conference Call
Coterra will host a conference call tomorrow, Thursday, February 24, 2022, at 9:00 AM CT (10:00 AM ET), to discuss fourth-quarter and full-year 2021 financial and operating results and its 2022 outlook.
Conference Call Information
Date: Thursday, February 24, 2022
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 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.
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: | |||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
2021 | 2020 | 2021 | 2020 | ||||
PRODUCTION VOLUMES | |||||||
Marcellus Shale | |||||||
Natural gas (Bcf) | 229.4 | 218.4 | 853.0 | 857.2 | |||
Equivalent production (MMBoe) | 38.0 | 36.0 | 142.0 | 143.0 | |||
Daily equivalent production (MBoepd) | 415.5 | 395.6 | 389.5 | 390.4 | |||
Permian Basin | |||||||
Natural gas (Bcf) | 41.3 | — | 41.3 | — | |||
Oil (MMBbl) | 7.4 | — | 7.4 | — | |||
NGL (MMBbl) | 5.1 | — | 5.1 | — | |||
Equivalent production (MMBoe) | 19.5 | — | 19.5 | — | |||
Daily equivalent production (MBoepd) | 211.5 | — | 211.5 | — | |||
Anadarko Basin | |||||||
Natural gas (Bcf) | 16.5 | — | 16.5 | — | |||
Oil (MMBbl) | 0.7 | — | 0.7 | — | |||
NGL (MMBbl) | 2.0 | — | 2.0 | — | |||
Equivalent production (MMBoe) | 5.4 | — | 5.4 | — | |||
Daily equivalent production (MBoepd) | 58.7 | — | 58.7 | — | |||
Total Company(1) | |||||||
Natural gas (Bcf) | 287.3 | 218.5 | 911.1 | 857.7 | |||
Oil (MMBbl) | 8.1 | — | 8.1 | — | |||
NGL (MMBbl) | 7.1 | — | 7.1 | — | |||
Equivalent production (MMBoe) | 63.1 | 36.0 | 167.1 | 143.0 | |||
Daily equivalent production (MBoepd) | 686.2 | 395.8 | 457.8 | 390.6 | |||
AVERAGE SALES PRICE (excluding hedges) | |||||||
Marcellus Shale | |||||||
Natural gas ($/Mcf) | $ 4.43 | $ 1.89 | $ 2.98 | $ 1.64 | |||
Permian Basin | |||||||
Natural gas ($/Mcf) | $ 4.13 | $ — | $ 4.13 | $ — | |||
Oil ($/Bbl) | $ 75.53 | $ — | $ 75.53 | $ — | |||
NGL ($/Bbl) | $ 33.25 | $ — | $ 33.25 | $ — | |||
Anadarko Basin | |||||||
Natural gas ($/Mcf) | $ 5.19 | $ — | $ 5.19 | $ — | |||
Oil ($/Bbl) | $ 76.49 | $ — | $ 76.49 | $ — | |||
NGL ($/Bbl) | $ 36.61 | $ — | $ 36.61 | $ — | |||
Total Company | |||||||
Natural gas ($/Mcf) | $ 4.43 | $ 1.89 | $ 3.07 | $ 1.64 | |||
Oil ($/Bbl) | $ 75.61 | $ — | $ 75.61 | $ — | |||
NGL ($/Bbl) | $ 34.18 | $ — | $ 34.18 | $ — | |||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
2021 | 2020 | 2021 | 2020 | ||||
AVERAGE SALES PRICE (including hedges) | |||||||
Total Company | |||||||
Natural gas ($/Mcf) | $ 3.57 | $ 1.90 | $ 2.73 | $ 1.68 | |||
Oil ($/Bbl) | $ 60.35 | $ — | $ 60.35 | $ — | |||
NGL ($/Bbl) | $ 34.18 | $ — | $ 34.18 | $ — | |||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
2021 | 2020 | 2021 | 2020 | ||||
WELLS DRILLED(2) | |||||||
Gross wells | |||||||
Marcellus Shale | 22 | 19 | 95 | 74 | |||
Permian Basin | 19 | — | 19 | — | |||
Anadarko Basin | — | — | — | — | |||
41 | 19 | 114 | 74 | ||||
Net wells | |||||||
Marcellus Shale | 19.1 | 15.0 | 89.2 | 64.3 | |||
Permian Basin | 10.7 | — | 10.7 | — | |||
Anadarko Basin | — | — | — | — | |||
29.8 | 15.0 | 99.9 | 64.3 | ||||
WELLS COMPLETED(2) | |||||||
Gross wells | |||||||
Marcellus Shale | 21 | 15 | 92 | 86 | |||
Permian Basin | 36 | — | 36 | — | |||
Anadarko Basin | 4 | — | 4 | — | |||
61 | 15 | 132 | 86 | ||||
Net wells | |||||||
Marcellus Shale | 21.0 | 15.0 | 88.1 | 77.3 | |||
Permian Basin | 20.2 | — | 20.2 | — | |||
Anadarko Basin | — | — | — | — | |||
41.2 | 15.0 | 108.3 | 77.3 | ||||
TURN IN LINES | |||||||
Gross wells | |||||||
Marcellus Shale | 22 | 22 | 92 | 75 | |||
Permian Basin | 33 | — | 33 | — | |||
Anadarko Basin | 4 | — | 4 | — | |||
59 | 22 | 129 | 75 | ||||
Net wells | |||||||
Marcellus Shale | 22.0 | 20.1 | 88.1 | 69.2 | |||
Permian Basin | 18.5 | — | 18.5 | — | |||
Anadarko Basin | — | — | — | — | |||
40.5 | 20.1 | 106.6 | 69.2 | ||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
2021 | 2020 | 2021 | 2020 | ||||
AVERAGE UNIT COSTS ($/Boe)(3) | |||||||
Direct operations | $ 1.62 | $ 0.50 | $ 0.93 | $ 0.51 | |||
Transportation, processing and gathering | 3.87 | 4.03 | 3.97 | 3.99 | |||
Taxes other than income | 1.05 | 0.08 | 0.50 | 0.10 | |||
Exploration | 0.14 | 0.11 | 0.11 | 0.10 | |||
Depreciation, depletion and amortization | 6.49 | 2.69 | 4.15 | 2.73 | |||
General and administrative (excluding stock-based compensation and merger-related expense)(4) | 1.52 | 0.50 | 0.84 | 0.44 | |||
Stock-based compensation | 0.49 | 0.19 | 0.34 | 0.30 | |||
Merger-related expense | 0.41 | — | 0.43 | 0.07 | — | ||
Interest expense | 0.38 | 0.31 | 0.37 | 0.07 | 0.38 | ||
$ 15.97 | $ 8.41 | $ 11.64 | $ 8.55 | ||||
_______________________________________________________________________________
(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. |
Derivatives Information |
The table below summarizes the Company's outstanding derivative contracts as of February 23, 2022. |
As of December 31, 2021, the Company had the following outstanding financial commodity derivatives: |
Collars | Swaps | |||||||||||||||
Floor | Ceiling | Basis Swaps | Roll Swaps | |||||||||||||
Type of Contract | Volume | Contract Period | Range | Weighted | Range | Weighted | Weighted | Weighted | ||||||||
Crude oil (WTI) | 630 | Jan. 2022-Mar. 2022 | $— | $ 35.00 | $ 45.28 | |||||||||||
Crude oil (WTI) | 1,629 | Jan. 2022-Jun. 2022 | $ 36.11 | $ 49.97 | ||||||||||||
Crude oil (WTI) | 2,730 | Jan. 2022-Sep. 2022 | $— | $ 40.00 | $ 49.19 | |||||||||||
Crude oil (WTI) | 2,920 | Jan. 2022-Dec. 2022 | $— | $ 57.00 | $ 72.43 | |||||||||||
Crude oil (WTI Midland)(1) | 630 | Jan. 2022-Mar. 2022 | $ 0.11 | |||||||||||||
Crude oil (WTI Midland)(1) | 1,448 | Jan. 2022-Jun. 2022 | $ 0.25 | |||||||||||||
Crude oil (WTI Midland)(1) | 1,911 | Jan. 2022-Sep. 2022 | $ 0.38 | |||||||||||||
Crude oil (WTI Midland)(1) | 2,920 | Jan. 2022-Dec. 2022 | $ 0.05 | |||||||||||||
Crude oil (WTI) | 630 | Jan. 2022-Mar. 2022 | $ (0.24) | |||||||||||||
Crude oil (WTI) | 724 | Jan. 2022-Jun. 2022 | $ (0.20) | |||||||||||||
Crude oil (WTI) | 1,911 | Jan. 2022-Sep. 2022 | $ 0.10 | |||||||||||||
________________________________________________________
(1) | The index price the Company pays under these basis swaps is WTI Midland, as quoted by Argus Americas Crude. |
Collars | ||||||||||||
Floor | Ceiling | |||||||||||
Type of Contract | Volume | Contract Period | Range ($/Mmbtu) | Weighted- ($/Mmbtu) | Range ($/Mmbtu) | Weighted- ($/Mmbtu) | ||||||
Natural gas (NYMEX) | 36,000,000 | Jan. 2022-Mar. 2022 | $ 4.38 | $ 6.97 | ||||||||
Natural gas (NYMEX) | 42,800,000 | Apr. 2022 - Oct. 2022 | $ 3.19 | $ 4.30 | ||||||||
Natural gas (Perm EP)(1) | 1,800,000 | Jan. 2022-Mar. 2022 | $ 1.85 | $ 2.18 | ||||||||
Natural gas (Perm EP)(1) | 3,620,000 | Jan. 2022-Jun. 2022 | $— | $ 2.40 | $ 2.88 | |||||||
Natural gas (Perm EP)(1) | 7,300,000 | Jan. 2022-Dec. 2022 | $— | $ 2.50 | $— | $ 3.15 | ||||||
Natural gas (PEPL)(2) | 3,600,000 | Jan. 2022-Mar. 2022 | $ 2.00 | $ 2.40 | ||||||||
Natural gas (PEPL)(2) | 3,620,000 | Jan. 2022-Jun. 2022 | $— | $ 2.40 | $ 2.86 | |||||||
Natural gas (PEPL)(2) | 7,300,000 | Jan. 2022-Dec. 2022 | $— | $ 2.60 | $— | $ 3.27 | ||||||
Natural gas (Waha)(3) | 3,600,000 | Jan. 2022-Mar. 2022 | $ 1.77 | $ 2.15 | ||||||||
Natural gas (Waha)(3) | 3,620,000 | Jan. 2022-Jun. 2022 | $— | $ 2.40 | $ 2.86 | |||||||
Natural gas (Waha)(3) | 2,730,000 | Jan. 2022-Sep. 2022 | $— | $ 2.40 | $— | $ 2.77 | ||||||
Natural gas (Waha)(3) | 7,300,000 | Jan. 2022-Dec. 2022 | $— | $ 2.50 | $— | $ 3.12 | ||||||
_______________________________________________________
(1) | The index price for these collars is El Paso Natural Gas Company, Permian Basin Index ("Perm EP"), as quoted in Platt's Inside FERC. |
(2) | The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index ("PEPL"), as quoted in Platt's Inside FERC. |
(3) | The index price for these collars is Waha West Texas Natural Gas Index ("Waha"), as quoted in Platt's Inside FERC. |
In early 2022, the Company entered into the following outstanding financial commodity derivatives:
Collars | ||||||||||||
Floor | Ceiling | |||||||||||
Type of Contract | Volume (Mmbtu) | Contract Period | Range ($/Mmbtu) | Weighted- Average ($/Mmbtu) | Range ($/Mmbtu) | Weighted- Average ($/Mmbtu) | ||||||
Natural gas (NYMEX) | 71,500,000 | Apr. 2022-Dec. 2022 | $ 3.84 | $ 5.39 | ||||||||
Natural gas (NYMEX) | 10,700,000 | Apr. 2022-Oct. 2022 | $ — | $ 4.00 | $ 5.63 | |||||||
Natural gas (NYMEX) | 7,550,000 | Nov. 2022-Mar. 2023 | $ — | $ 4.00 | $ 7.08 | |||||||
Year-End Proved Reserves
The tables below provide a summary of changes in proved reserves for the year ended December 31, 2021.
Oil | Natural Gas | NGL | Total | ||||
PROVED RESERVES | |||||||
December 31, 2020 | 15 | 13,672 | — | 2,278,636 | |||
Revision of previous estimates | 10,837 | (538) | 16,797 | (61,967) | |||
Extensions and discoveries | 2,633 | 973 | 6,100 | 170,988 | |||
Purchases of reserves | 184,094 | 1,699 | 204,822 | 672,038 | |||
Production | (8,150) | (911) | (7,104) | (167,113) | |||
Sales of reserves | — | — | — | — | |||
December 31, 2021 | 189,429 | 14,895 | 220,615 | 2,892,582 | |||
PROVED DEVELOPED RESERVES | |||||||
December 31, 2020 | 15 | 8,608 | — | 1,434,714 | |||
December 31, 2021 | 153,010 | 10,691 | 193,598 | 2,128,439 | |||
PROVED RESERVES BY REGION | |||||||
Marcellus Shale | 5 | 13,076 | — | 2,179,268 | |||
Permian Basin | 170,354 | 1,169 | 149,063 | 514,184 | |||
Anadarko Basin | 18,749 | 648 | 71,406 | 198,188 | |||
Other | 321 | 2 | 146 | 942 | |||
189,429 | 14,895 | 220,615 | 2,892,582 |
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited) | |||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
(In millions, except per share amounts) | 2021 | 2020 | 2021 | 2020 | |||
OPERATING REVENUES | |||||||
Natural gas | $ 1,272 | $ 413 | $ 2,798 | $ 1,405 | |||
Oil | 616 | — | 616 | — | |||
NGL | 243 | — | 243 | — | |||
Gain (loss) on derivative instruments | 81 | 43 | (221) | 61 | |||
Other | 13 | — | 13 | — | |||
2,225 | 456 | 3,449 | 1,466 | ||||
OPERATING EXPENSES | |||||||
Direct operations | 102 | 18 | 156 | 73 | |||
Transportation, processing and gathering | 244 | 145 | 663 | 571 | |||
Taxes other than income | 66 | 3 | 83 | 14 | |||
Exploration | 9 | 5 | 18 | 15 | |||
Depreciation, depletion and amortization | 410 | 97 | 693 | 391 | |||
General and administrative (excluding stock-based compensation and merger-related costs)(1) | 96 | 18 | 141 | 63 | |||
Stock-based compensation(2) | 31 | 7 | 57 | 43 | |||
Merger-related expense | 26 | — | 72 | — | |||
984 | 293 | 1,883 | 1,170 | ||||
Loss on sale of assets | (2) | — | (2) | — | |||
INCOME FROM OPERATIONS | 1,239 | 163 | 1,564 | 296 | |||
Interest expense, net | 24 | 11 | 62 | 54 | |||
Income before income taxes | 1,215 | 152 | 1,502 | 242 | |||
Income tax expense | 276 | 21 | 344 | 41 | |||
NET INCOME | $ 939 | $ 131 | $ 1,158 | $ 201 | |||
Earnings per share - Basic | $ 1.16 | $ 0.33 | $ 2.30 | $ 0.50 | |||
Weighted-average common shares outstanding | 810 | 399 | 503 | 399 | |||
_______________________________________________________________________________
(1) | For the three months ended December 31, 2021, includes severance expense of |
(2) | Includes the impact of our performance share awards and restricted stock. |
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited) | |||
(In millions) | December 31, | December 31, | |
ASSETS | |||
Current assets | $ 2,136 | $ 416 | |
Properties and equipment, net (successful efforts method) | 17,375 | 4,045 | |
Other assets | 389 | 63 | |
$ 19,900 | $ 4,524 | ||
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | |||
Current liabilities | $ 1,220 | $ 202 | |
Current portion of long-term debt | — | 188 | |
Long-term debt, net (excluding current maturities) | 3,125 | 946 | |
Deferred income taxes | 3,101 | 774 | |
Other liabilities | 666 | 198 | |
Cimarex redeemable preferred stock | 50 | — | |
Stockholders' equity | 11,738 | 2,216 | |
$ 19,900 | $ 4,524 | ||
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) | |||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
(In millions) | 2021 | 2020 | 2021 | 2020 | |||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||
Net income | $ 939 | $ 131 | $ 1,158 | $ 201 | |||
Depreciation, depletion and amortization | 410 | 97 | 693 | 391 | |||
Deferred income tax expense | 109 | 25 | 126 | 72 | |||
Loss on sale of assets | 2 | — | 2 | — | |||
Exploratory dry hole cost | — | 2 | — | 4 | |||
(Gain) loss on derivative instruments | (81) | (43) | 221 | (61) | |||
Net cash (paid) received in settlement of derivative instruments | (370) | 1 | (431) | 35 | |||
Stock-based compensation and other | 29 | 5 | 52 | 40 | |||
Income charges not requiring cash | (12) | 1 | (10) | 3 | |||
Changes in assets and liabilities | (73) | 88 | (144) | 93 | |||
Net cash provided by operating activities | 953 | 307 | 1,667 | 778 | |||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||
Capital expenditures | (268) | (98) | (728) | (576) | |||
Proceeds from sale of assets | 8 | 1 | 8 | 1 | |||
Proceeds from sale of equity method investments | — | — | — | (9) | |||
Cash received from Merger | 1,033 | — | 1,033 | — | |||
Net cash provided by (used in) investing activities | 773 | (97) | 313 | (584) | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||
Net borrowings (repayments) of debt | — | (28) | (188) | (87) | |||
Repayment of finance leases | (2) | — | (2) | — | |||
Dividends paid | (652) | (40) | (780) | (159) | |||
Tax withholding on vesting of stock awards | (109) | (3) | (114) | (10) | |||
Capitalized debt issuance costs | (4) | — | (4) | — | |||
Cash received for stock option exercises | 2 | — | 2 | — | |||
Net cash used in financing activities | (765) | (71) | (1,086) | (256) | |||
Net increase (decrease) in cash, cash equivalents and restricted cash | $ 961 | $ 139 | $ 894 | $ (62) | |||
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.
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.
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
(In millions, except per share amounts) | 2021 | 2020 | 2021 | 2020 | |||
As reported - net income | $ 939 | $ 131 | $ 1,158 | $ 201 | |||
Reversal of selected items: | |||||||
Loss on sale of assets | 2 | — | 2 | — | |||
(Gain) loss on derivative instruments(1) | (451) | (42) | (210) | (26) | |||
Stock-based compensation expense | 31 | 7 | 57 | 43 | |||
Severance expense | 44 | — | 46 | — | |||
Merger-related expense | 26 | — | 72 | — | |||
Tax effect on selected items | 79 | 8 | 7 | (4) | |||
Adjusted net income | $ 670 | $ 104 | $ 1,132 | $ 214 | |||
As reported - earnings per share | $ 1.16 | $ 0.33 | $ 2.30 | $ 0.50 | |||
Per share impact of selected items | (0.33) | (0.07) | (0.05) | 0.04 | |||
Adjusted earnings per share | $ 0.83 | $ 0.26 | $ 2.25 | $ 0.54 | |||
Weighted-average common shares outstanding | 810 | 399 | 503 | 399 | |||
_______________________________________________________________________________
(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. |
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 flow from operating activities or net income, as defined by GAAP, or as a measure of liquidity.
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||
(In millions) | 2021 | 2020 | 2021 | 2020 | ||||
Cash flow from operating activities | $ 953 | $ 307 | $ 1,667 | $ 778 | ||||
Changes in assets and liabilities | 73 | (88) | 144 | (93) | ||||
Discretionary cash flow | 1,026 | 219 | 1,811 | 685 | ||||
Cash paid for capital expenditures | (268) | (98) | (728) | (576) | ||||
Free cash flow | $ 758 | $ 121 | $ 1,083 | $ 109 | ||||
Variable Dividend Calculation | ||
(In millions) | Three Months Ended December 31, 2021 | |
Free cash flow | $ 758 | |
60 % | ||
Quarterly return to shareholders | 455 | |
Quarterly base dividend ( | 122 | |
Variable cash dividend ( | $ 333 | |
Capital Expenditures | ||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||
(In millions) | 2021 | 2020 | 2021 | 2020 | ||||
Cash paid for capital expenditures | $ 268 | $ 98 | $ 728 | $ 576 | ||||
Change in accrued capital costs | (4) | 10 | (3) | (2) | ||||
Exploratory dry-hole cost | — | (2) | — | (4) | ||||
Capital expenditures | $ 264 | $ 106 | $ 725 | $ 570 | ||||
Reconciliation of EBITDAX
EBITDAX is defined as net income plus interest expense, other expense, income tax expense and benefit, depreciation, depletion, and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense and merger-related expense. 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.
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||
(In millions) | 2021 | 2020 | 2021 | 2020 | |||
Net income | $ 939 | $ 131 | $ 1,158 | $ 201 | |||
Plus (less): | |||||||
Interest expense, net | 24 | 11 | 62 | 54 | |||
Income tax expense | 276 | 21 | 344 | 41 | |||
Depreciation, depletion and amortization | 410 | 97 | 693 | 391 | |||
Exploration | 9 | 5 | 18 | 15 | |||
Loss on sale of assets | 2 | — | 2 | — | |||
Non-cash (gain) loss on derivative instruments | (451) | (42) | (210) | (26) | |||
Stock-based compensation | 31 | 7 | 57 | 43 | |||
Merger-related expense | 26 | — | 72 | — | |||
EBITDAX | $ 1,266 | $ 230 | $ 2,196 | $ 719 | |||
Cimarex EBITDAX (nine months ended September 30, 2021) | — | — | 1,005 | — | |||
Combined EBITDAX | $ 3,201 | ||||||
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, | December 31, | |
Current portion of long-term debt | $ — | $ 188 | |
Long-term debt, net | 3,125 | 946 | |
Total debt | $ 3,125 | $ 1,134 | |
Stockholders' equity | 11,738 | 2,216 | |
Total capitalization | $ 14,863 | $ 3,350 | |
Total debt | $ 3,125 | $ 1,134 | |
Less: Cash and cash equivalents | (1,036) | (140) | |
Net debt | $ 2,089 | $ 994 | |
Net debt | $ 2,089 | $ 994 | |
Stockholders' equity | 11,738 | 2,216 | |
Total adjusted capitalization | $ 13,827 | $ 3,210 | |
Total debt to total capitalization ratio | 21.0 % | 33.9 % | |
Less: Impact of cash and cash equivalents | 5.9 % | 2.9 % | |
Net debt to adjusted capitalization ratio | 15.1 % | 31.0 % |
Reconciliation of Net Debt to EBITDAX - Coterra
Net debt to EBITDAX is defined as net debt divided by trailing twelve month EBITDAX. Net debt to 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, | December 31, | |
Net debt | $ 2,089 | $ 994 | |
EBITDAX (Twelve months ended December 31) | 2,196 | 719 | |
Net debt to EBITDAX | 0.95 x | 1.38 x |
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, |
Net debt | $ 2,089 |
EBITDAX (Twelve months ended December 31) | 3,201 |
Net debt to EBITDAX | 0.65 x |
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SOURCE Coterra Energy Inc.
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