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HOUSTON, Nov. 3, 2022 /PRNewswire/ -- Coterra Energy Inc. (NYSE: CTRA) ("Coterra" or the "Company") today reported third-quarter 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"). Referenced results for the three and nine months ended September 30, 2021 reflect only legacy Cabot. Referenced results for the three and nine months ended September 30, 2022 reflect the combined Company.
Thomas E. Jorden, Chief Executive Officer and President, commented, "Coterra continues to execute and has delivered another strong operational quarter with outsized shareholder returns. Just over one year since the formation of this company, I am extremely proud of what we have accomplished and am excited for the future. I am proud of our employees' commitment to excellence and a culture that will continue to be a differentiated competitive advantage. As a low-cost operator of diversified, top-tier assets, and with a market-leading balance sheet, Coterra is positioned to succeed through cycles."
Third-Quarter 2022 Highlights
Shareholder Return Highlights
Jorden added, "We are pleased to announce that we will return 74 percent of our third-quarter 2022 free cash flow to shareholders, which includes 50 percent in the form of cash dividends and 24 percent in the form of share repurchases. Driven by strong operational execution and healthy commodity prices during the quarter, our cash dividends increased 5 percent over the second quarter of 2022. We remain committed to returning 50 percent plus of free cash flow via dividends, supplemented by share repurchases, and potential future debt reduction."
Marcellus Update
In late first-quarter 2022, Coterra brought online a seven well Upper Marcellus development. As noted in our updated corporate presentation, the Upper Marcellus development, after six months, has produced an average cumulative volume of 324 Mcf/Lateral Foot. This compares to the Company's average Lower Marcellus 2021-2022 well performance which averaged 406 Mcf/Lateral Foot. With future Upper Marcellus development costs expected to be 10-15 percent per foot less than Lower Marcellus development costs, the Upper Marcellus capital efficiency is competitive with the Company's Lower Marcellus and broader asset portfolio. At a flat $4.25 NYMEX gas price, the recent Upper Marcellus development is estimated to generate a PVI10 of 2.6x, which compares favorably to the 140 Lower Marcellus wells drilled in 2021-2022 that are estimated to generate a PVI10 of 2.8x. See "Supplemental Non-GAAP Financial Measures (Unaudited)" for our definition of PVI10.
Driven by strong well performance, the Company's 2022 Marcellus production continues to trend above originally budgeted expectations.
Activity Outlook and Guidance Update
Coterra is currently running six rigs and two completion crews in the Permian Basin and three rigs and one completion crew in the Marcellus.
Production volumes in fourth-quarter 2022 are expected to average between 615 and 635 MBoepd, with oil volumes estimated to average between 86 and 89 MBopd. Natural gas volumes in fourth-quarter are projected to average between 2,725 and 2,775 MMcfpd.
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.
Year-to-date 2022 Summary Highlights
Strong Financial Position
Coterra maintains a strong financial position with investment-grade credit ratings and substantial liquidity. As of September 30, 2022, Coterra had total long-term debt of $2.2 billion with a principal amount of $2.1 billion. The Company exited the quarter with a cash balance of $778 million, no debt outstanding under its revolving credit facility, and no near-term debt maturities. Coterra's net debt to Adjusted EBITDAX ratio (non-GAAP) at September 30, 2022 was 0.2x.
Proved Reserves Update
In connection with the Merger, we have continued to evaluate and refine our process for assessing the estimated proved reserves of our legacy Cimarex and Cabot operations. Based on the analysis to date, as of September 30, 2022, we anticipate our total company proved reserves will decrease by approximately 15-20 percent year over year at December 31, 2022. This decrease in proved reserves is driven by a downward revision to prior estimates of approximately 32-36 percent for our Marcellus Shale properties, partially offset by an upward revision of approximately 8-12 percent for our Permian and Anadarko properties. Approximately a quarter of the estimated total revision volume in the Marcellus Shale is related to the SEC 5-year rule for proved undeveloped reserves (PUDs) due to the timing of capital investments, changes around well spacing, and location optimization within the Marcellus Region. Factors that may impact the size of the total adjustment include commodity prices, well performance, operating expenses and the completion of the annual PUD reserves process, which will be incorporated as of year-end 2022. The expected net downward revision of prior estimates did not have a material impact on our Condensed Consolidated Financial Statements as of and for the period ended September 30, 2022 and is not expected to have a material impact on our 2022 and go-forward Consolidated Financial Statements.
Mr. Jorden commented, "The revision noted above spans the 50-year life of these wells and is not material to our financials, nor to the go-forward economics of the Marcellus play. These revisions are not expected to have any significant impact on our near-term cash flows or capital allocation. After accounting for these adjustments to our estimated total proved reserves, we expect our year-end 2022 standardized measure of future net cash flows to increase significantly from year-end 2021, driven by higher commodity prices."
Committed to Sustainability and ESG Leadership
Coterra believes that environmental, social and governance (ESG) performance and practices are foundational to our success. Today we published the first Coterra Energy Sustainability Report, which can be accessed on the "Sustainable Future" section of our website at www.coterra.com.
Third-Quarter 2022 Conference Call
Coterra will host a conference call tomorrow, Friday, November 4, 2022, at 9:00 AM CT (10:00 AM ET), to discuss third-quarter 2022 financial and operating results.
Conference Call Information
Date: November 4, 2022
Time: 10:00 AM ET / 9:00 AM CT
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 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, 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 first 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" 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 combined businesses will not be integrated successfully; the risk that the cost savings and any other synergies from the Merger may not be fully realized or may take longer to realize than expected; the volatility in commodity prices for crude oil and natural gas; cost increases; supply chain disruptions; 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 Merger making it more difficult to maintain relationships with customers, employees or suppliers; the diversion of management time on integration-related issues; the potential effects of further developments to the long-term impact of the COVID-19 pandemic and variants 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; 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); determination of reserves estimates, adjustments or revisions, including factors impacting such determination such as commodity prices, well performance, operating expenses and completion of Coterra's annual PUD reserves process, as well as the impact on our financial statements resulting therefrom; the presence or recoverability of estimated reserves; the ability to replace reserves; environmental risks; drilling and operating risks; exploration and development risks; competition; the ability of management to execute its plans to meet its goals; and other risks inherent in Coterra's businesses. In addition, the declaration and payment of any future dividends, whether regular base quarterly dividends, variable dividends or special dividends, will depend on Coterra's financial results, cash requirements, future prospects and other factors deemed relevant by Coterra's Board. While the list of factors presented here is considered representative, no such list should be considered to be a complete statement of all potential risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. For additional information about other factors that could cause actual results to differ materially from those described in the forward-looking statements, please refer to Coterra's annual report 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.
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
September 30,
Nine Months Ended
September 30,
2022
2021
2022
2021
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Bcf)
203.7
217.4
607.4
623.9
Equivalent production (MMBoe)
34.0
36.2
101.2
104.0
Daily equivalent production (MBoepd)
369.1
394.0
370.8
380.9
Permian Basin
Natural gas (Bcf)
37.8
—
114.2
—
Oil (MMBbl)
7.6
—
22.0
—
NGL (MMBbl)
6.0
—
16.4
—
Equivalent production (MMBoe)
19.9
—
57.5
—
Daily equivalent production (MBoepd)
216.4
—
210.5
—
Anadarko Basin
Natural gas (Bcf)
16.5
—
46.5
—
Oil (MMBbl)
0.5
—
1.6
—
NGL (MMBbl)
1.9
—
5.1
—
Equivalent production (MMBoe)
5.1
—
14.4
—
Daily equivalent production (MBoepd)
55.5
—
52.7
—
Total Company
Natural gas (Bcf)
258.2
217.4
768.5
623.9
Oil (MMBbl)
8.1
—
23.6
—
NGL (MMBbl)
7.9
—
21.5
—
Equivalent production (MMBoe)
59.0
36.2
173.2
104.0
Daily equivalent production (MBoepd)
641.2
394.0
634.4
380.9
AVERAGE SALES PRICE (excluding hedges)
Marcellus Shale
Natural gas ($/Mcf)
$ 6.20
$ 2.95
$ 5.33
$ 2.45
Permian Basin
Natural gas ($/Mcf)
$ 6.63
$ —
$ 5.88
$ —
Oil ($/Bbl)
$ 93.40
$ —
$ 98.81
$ —
NGL ($/Bbl)
$ 31.84
$ —
$ 35.56
$ —
Anadarko Basin
Natural gas ($/Mcf)
$ 7.78
$ —
$ 6.62
$ —
Oil ($/Bbl)
$ 92.60
$ —
$ 98.38
$ —
NGL ($/Bbl)
$ 35.81
$ —
$ 39.28
$ —
Total Company
Natural gas ($/Mcf)
$ 6.37
$ 2.95
$ 5.49
$ 2.45
Oil ($/Bbl)
$ 93.35
$ —
$ 98.78
$ —
NGL ($/Bbl)
$ 32.78
$ —
$ 36.44
$ —
Quarter Ended
September 30,
Nine Months Ended
September 30,
2022
2021
2022
2021
AVERAGE SALES PRICE (including hedges)
Total Company
Natural gas ($/Mcf)
$ 5.58
$ 2.65
$ 4.97
$ 2.35
Oil ($/Bbl)
$ 86.37
$ —
$ 85.31
$ —
NGL ($/Bbl)
$ 32.78
$ —
$ 36.44
$ —
Quarter Ended
September 30,
Nine Months Ended
September 30,
2022
2021
2022
2021
WELLS DRILLED(1)
Gross wells
Marcellus Shale
24
17
66
73
Permian Basin
46
—
118
—
Anadarko Basin
9
—
22
—
79
17
206
73
Net wells
Marcellus Shale
24.0
17.0
66.0
70.1
Permian Basin
19.2
—
59.0
—
Anadarko Basin
2.3
—
8.8
—
45.5
17.0
133.8
70.1
WELLS COMPLETED(1)
Gross wells
Marcellus Shale
18
30
62
71
Permian Basin
35
—
91
—
Anadarko Basin
6
—
15
—
59
30
168
71
Net wells
Marcellus Shale
18.0
30.0
59.0
67.1
Permian Basin
15.8
—
42.3
—
Anadarko Basin
2.0
—
2.8
—
35.8
30.0
104.1
67.1
TURN IN LINES
Gross wells
Marcellus Shale
27
31
57
70
Permian Basin
38
—
105
—
Anadarko Basin
7
—
15
—
72
31
177
70
Net wells
Marcellus Shale
25.0
31.0
52.1
67.1
Permian Basin
18.0
—
47.8
—
Anadarko Basin
2.7
—
2.8
—
45.7
31.0
102.7
67.1
Quarter Ended
September 30,
Nine Months Ended
September 30,
2022
2021
2022
2021
AVERAGE UNIT COSTS ($/Boe)(2)
Direct operations
$ 1.99
$ 0.59
$ 1.93
$ 0.52
Transportation, processing and gathering
4.33
4.10
4.19
4.03
Taxes other than income
1.72
0.23
1.59
0.17
Exploration
0.17
0.11
0.13
0.09
Depreciation, depletion and amortization
7.16
2.68
6.91
2.72
General and administrative (excluding stock-based compensation and merger-related expense)(3)
1.14
0.41
0.99
0.43
Stock-based compensation
0.44
0.28
0.40
0.25
Merger-related expense
0.22
1.11
0.34
0.45
Interest expense
0.29
0.35
0.34
0.36
$ 17.45
$ 9.86
$ 16.83
$ 9.02
_______________________________________________________________________________
(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.
(3)
For the nine months ended September 30, 2022, includes severance expense related to accrued severance costs as a result of the Merger. For the nine months ended September 30, 2021, includes severance expense related to early retirements under the Company's 2021 Early Retirement Program.
Variable Dividend Calculation
(In millions)
Quarter Ended
September 30, 2022
Free cash flow(1)
$ 1,064
50% payout (Board discretion: 50% plus)
50 %
Quarterly return to shareholders(2)
532
Quarterly base dividend(2) ($0.150 per share)
118
Variable cash dividend (2)
$ 414
_______________________________________________________________________________
(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.
Derivatives Information
As of September 30, 2022, the Company had the following outstanding financial commodity derivatives:
2022
2023
Natural Gas
Fourth
Quarter
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Waha swaps(1)
Volume (MMBtu)
1,550,000
—
—
—
—
Weighted average price
$ 4.77
$ —
$ —
$ —
$ —
Waha gas collars(1)
Volume (MMBtu)
1,840,000
8,100,000
8,190,000
8,280,000
8,280,000
Weighted average floor
$ 2.50
$ 3.03
$ 3.03
$ 3.03
$ 3.03
Weighted average ceiling
$ 3.12
$ 5.39
$ 5.39
$ 5.39
$ 5.39
NYMEX collars
Volume (MMBtu)
63,770,000
40,500,000
4,550,000
4,600,000
1,550,000
Weighted average floor
$ 4.47
$ 5.14
$ 4.50
$ 4.50
$ 4.50
Weighted average ceiling
$ 7.20
$ 9.41
$ 8.39
$ 8.39
$ 8.39
El Paso Permian gas collars(2)
Volume (MMBtu)
1,840,000
—
—
—
—
Weighted average floor
$ 2.50
$ —
$ —
$ —
$ —
Weighted average ceiling
$ 3.15
$ —
$ —
$ —
$ —
PEPL gas collars(3)
Volume (MMBtu)
1,840,000
—
—
—
—
Weighted average floor
$ 2.60
$ —
$ —
$ —
$ —
Weighted average ceiling
$ 3.27
$ —
$ —
$ —
$ —
Leidy basis swaps (4)
Volume (MMBtu)
1,550,000
—
—
—
—
Weighted average price
$ (1.50)
$ —
$ —
$ —
$ —
________________________________________________________
(1)
The index price is Waha West Texas Natural Gas Index ("Waha") as quoted in Platt's Inside FERC.
(2)
The index price is El Paso Natural Gas Company, Permian Basin Index ("Perm EP") as quoted in Platt's Inside FERC.
(3)
The index price is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index ("PEPL") as quoted in Platt's Inside FERC.
(4)
The index price is Transco, Leidy Line receipts ("Leidy") as quoted in Platt's Inside FERC.
2022
2023
Oil
Fourth Quarter
First Quarter
Second Quarter
WTI oil collars
Volume (Mbbl)
2,116
1,350
1,365
Weighted average floor
$ 67.65
$ 70.00
$ 70.00
Weighted average ceiling
$ 112.50
$ 116.03
$ 116.03
WTI Midland oil basis swaps (1)
Volume (Mbbl)
2,116
1,350
1,365
Weighted average differential
$ 0.46
$ 0.63
$ 0.63
________________________________________________________
(1)
The index price is WTI Midland as quoted by Argus Americas Crude.
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
Quarter Ended
September 30,
Nine Months Ended
September 30,
(In millions, except per share amounts)
2022
2021
2022
2021
OPERATING REVENUES
Natural gas
$ 1,644
$ 641
$ 4,223
$ 1,526
Oil
755
—
2,330
—
NGL
259
—
784
—
Loss on derivative instruments
(156)
(201)
(613)
(302)
Other
18
—
47
—
2,520
440
6,771
1,224
OPERATING EXPENSES
Direct operations
118
21
334
54
Transportation, processing and gathering
255
149
726
419
Taxes other than income
102
8
276
17
Exploration
10
4
23
9
Depreciation, depletion and amortization
422
97
1,196
283
General and administrative (excluding stock-based compensation and merger-related expense)(1)
68
14
173
44
Stock-based compensation(2)
26
10
70
26
Merger-related expense
13
40
58
46
1,014
343
2,856
898
Loss on sale of assets
—
—
(1)
—
INCOME FROM OPERATIONS
1,506
97
3,914
326
Interest expense, net
17
13
59
38
Gain on debt extinguishment
(26)
—
(26)
—
Income before income taxes
1,515
84
3,881
288
Income tax expense
319
20
848
68
NET INCOME
$ 1,196
$ 64
$ 3,033
$ 220
Earnings per share - Basic
$ 1.51
$ 0.16
$ 3.78
$ 0.55
Weighted-average common shares outstanding
792
400
801
399
_______________________________________________________________________________
(1)
For the three and nine months ended September 30, 2022, includes severance expense of $12 million and $51 million, respectively, related to accrued severance costs as a result of the Merger. For the nine months ended September 30, 2021, includes $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.
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In millions)
September 30,
2022
December 31,
2021
ASSETS
Current assets
$ 2,350
$ 2,136
Properties and equipment, net (successful efforts method)
17,429
17,375
Other assets
526
389
$ 20,305
$ 19,900
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities
$ 1,371
$ 1,220
Current portion of long-term debt
44
—
Long-term debt, net (excluding current maturities)
2,188
3,125
Deferred income taxes
3,229
3,101
Other long term liabilities
803
666
Cimarex redeemable preferred stock
11
50
Stockholders' equity
12,659
11,738
$ 20,305
$ 19,900
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
Quarter Ended
September 30,
Nine Months Ended
September 30,
(In millions)
2022
2021
2022
2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
$ 1,196
$ 64
$ 3,033
$ 220
Depreciation, depletion and amortization
422
97
1,196
283
Deferred income tax expense
27
2
128
17
Loss on sale of assets
—
—
1
—
Loss on derivative instruments
156
201
613
302
Net cash paid in settlement of derivative instruments
(259)
(64)
(723)
(61)
Stock-based compensation and other
24
9
62
24
Income charges not requiring cash
(42)
1
(61)
2
Changes in assets and liabilities
247
(64)
(277)
(71)
Net cash provided by operating activities
1,771
246
3,972
716
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures
(460)
(184)
(1,205)
(459)
Proceeds from sale of assets
18
—
22
—
Net cash used in investing activities
(442)
(184)
(1,183)
(459)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) of debt
(830)
(100)
(830)
(188)
Repayment of finance leases
(1)
—
(4)
—
Treasury stock repurchases
(253)
—
(740)
—
Dividends paid
(519)
(44)
(1,459)
(128)
Tax withholding on vesting of stock awards
(8)
—
(15)
(6)
Cash received for stock option exercises
1
—
11
—
Cash paid for conversion of redeemable preferred stock
—
—
(10)
—
Net cash used in financing activities
(1,610)
(144)
(3,047)
(322)
Net decrease in cash, cash equivalents and restricted cash
$ (281)
$ (82)
$ (258)
$ (65)
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
September 30,
Nine Months Ended
September 30,
(In millions, except per share amounts)
2022
2021
2022
2021
As reported - net income
$ 1,196
$ 64
$ 3,033
$ 220
Reversal of selected items:
Loss on sale of assets
—
—
1
—
Loss (gain) on derivative instruments(1)
(103)
137
(110)
241
Stock-based compensation expense
26
10
70
26
Gain on debt extinguishment
(26)
—
(26)
—
Severance expense
12
—
51
2
Merger-related expense
1
40
7
46
Tax effect on selected items
20
(43)
2
(72)
Adjusted net income
$ 1,126
$ 208
$ 3,028
$ 463
As reported - earnings per share
$ 1.51
$ 0.16
$ 3.78
$ 0.55
Per share impact of selected items
(0.09)
0.36
—
0.61
Adjusted earnings per share
$ 1.42
$ 0.52
$ 3.78
$ 1.16
Weighted-average common shares outstanding
792
400
801
399
_______________________________________________________________________________
(1)
This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in 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 flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.
Quarter Ended
September 30,
Nine Months Ended
September 30,
(In millions)
2022
2021
2022
2021
Cash flow from operating activities
$ 1,771
$ 246
$ 3,972
$ 716
Changes in assets and liabilities
(247)
64
277
71
Discretionary cash flow
1,524
310
4,249
787
Cash paid for capital expenditures
(460)
(184)
(1,205)
(459)
Free cash flow
$ 1,064
$ 126
$ 3,044
$ 328
Capital Expenditures
Quarter Ended
September 30,
Nine Months Ended
September 30,
(In millions)
2022
2021
2022
2021
Cash paid for capital expenditures (GAAP)
$ 460
$ 184
$ 1,205
$ 459
Change in accrued capital costs
(4)
(13)
49
2
Capital expenditures
$ 456
$ 171
$ 1,254
$ 461
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
September 30,
Nine Months Ended
September 30,
(In millions)
2022
2021
2022
2021
Net income
$ 1,196
$ 64
$ 3,033
$ 220
Plus (less):
Interest expense, net
17
13
59
38
Gain on debt extinguishment
(26)
—
(26)
—
Income tax expense
319
20
848
68
Depreciation, depletion and amortization
422
97
1,196
283
Exploration
10
4
23
9
Loss on sale of assets
—
—
1
—
Non-cash loss on derivative instruments
(103)
137
(110)
241
Merger-related expense
1
40
7
46
Severance expense
12
—
51
2
Stock-based compensation
26
10
70
26
Adjusted EBITDAX
$ 1,874
$ 385
$ 5,152
$ 933
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)
September 30,
2022
December 31,
2021
Current portion of long-term debt
$ 44
$ —
Long-term debt, net
2,188
3,125
Total debt
2,232
3,125
Stockholders' equity
12,659
11,738
Total capitalization
$ 14,891
$ 14,863
Total debt
$ 2,232
$ 3,125
Less: Cash and cash equivalents
(778)
(1,036)
Net debt
$ 1,454
$ 2,089
Net debt
$ 1,454
$ 2,089
Stockholders' equity
12,659
11,738
Total adjusted capitalization
$ 14,113
$ 13,827
Total debt to total capitalization ratio
15.0 %
21.0 %
Less: Impact of cash and cash equivalents
4.7 %
5.9 %
Net debt to adjusted capitalization ratio
10.3 %
15.1 %
Reconciliation of Net Debt to Adjusted EBITDAX
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)
September 30,
2022
December 31,
2021
Net debt
$ 1,454
$ 2,089
Adjusted EBITDAX (Trailing twelve months)
6,463
2,196
Net debt to Adjusted EBITDAX
0.2 x
1.0 x
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SOURCE Coterra Energy Inc.