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."
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."
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.
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.
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.
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.
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.
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.
AVERAGE SALES PRICE (excluding hedges)
AVERAGE SALES PRICE (including hedges)
General and administrative (excluding stock-based compensation and merger-related expense)(3)
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.
Total unit costs may differ from the sum of the individual costs due to rounding.
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.
Quarterly base dividend(2) ($0.150 per share)
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.
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.
As of September 30, 2022, the Company had the following outstanding financial commodity derivatives:
El Paso Permian gas collars(2)
The index price is Waha West Texas Natural Gas Index ("Waha") as quoted in Platt's Inside FERC.
The index price is El Paso Natural Gas Company, Permian Basin Index ("Perm EP") as quoted in Platt's Inside FERC.
The index price is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index ("PEPL") as quoted in Platt's Inside FERC.
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.
WTI Midland oil basis swaps (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 STATEMENT OF OPERATIONS (Unaudited)
(In millions, except per share amounts)
General and administrative (excluding stock-based compensation and merger-related expense)(1)
Loss on sale of assets
Earnings per share - Basic
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.
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 BALANCE SHEET (Unaudited)
Properties and equipment, net (successful efforts method)
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current portion of long-term debt
Long-term debt, net (excluding current maturities)
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)
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Loss on sale of assets
Net cash paid in settlement of derivative instruments
Income charges not requiring cash
Changes in assets and liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of assets
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) of debt
Tax withholding on vesting of stock awards
Cash received for stock option exercises
Cash paid for conversion of redeemable preferred stock
Net cash used in financing activities
Net decrease in cash, cash equivalents and restricted cash
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.
(In millions, except per share amounts)
As reported - net income
Loss on sale of assets
Loss (gain) on derivative instruments(1)
Tax effect on selected items
As reported - earnings per share
Per share impact of selected items
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.
Cash flow from operating activities
Changes in assets and liabilities
Cash paid for capital expenditures
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
Cash paid for capital expenditures (GAAP)
Change in accrued capital costs
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.
Loss on sale of assets
Non-cash loss on derivative instruments
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.
Current portion of long-term debt
Less: Cash and cash equivalents
Total debt to total capitalization ratio
Less: Impact of cash and cash equivalents
Net debt to adjusted capitalization ratio
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.
Adjusted EBITDAX (Trailing twelve months)
Net debt to Adjusted EBITDAX
View original content:https://www.prnewswire.com/news-releases/coterra-energy-reports-third-quarter-2022-results-announces-quarterly-dividend-and-provides-update-on-share-repurchase-program-301668324.html
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