Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM10-Q
ý☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
For the quarterly period ended September 30, 2017March 31, 2022
oOR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
Commission file number 1-10447
CABOT OIL & GAS CORPORATIONCOTERRA ENERGY INC.
(Exact name of registrant as specified in its charter)
DELAWAREDelaware04-3072771
(State or other jurisdiction of

incorporation or organization)
(I.R.S. Employer

Identification Number)
Three Memorial City Plaza
840 Gessner Road, Suite 1400, Houston, Texas 77024
(Address of principal executive offices, including ZIP code)
(281) 589-4600
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.10 per shareCTRANew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ý☒ No o☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý☒ No o☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging“emerging growth company"company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer☒Accelerated filer☐
Large accelerated filer ý
Accelerated filer o
Non-accelerated filero
☐
Smaller reporting companyo
☐
(Do not check if a smaller reporting company)
Emerging growth companyo
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐ No ý☒
As of October 23, 2017,May 2, 2022, there were 462,508,414805,805,159 shares of Common Stock, Par Value $0.10 Per Share, outstanding.


CABOT OIL & GAS CORPORATION
Table of Contents
COTERRA ENERGY INC.
INDEX TO FINANCIAL STATEMENTS
Page
Item 1.
Condensed Consolidated Balance Sheet (Unaudited) at September 30, 2017March 31, 2022 and December 31, 20162021
3
Condensed Consolidated Statement of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2017March 31, 2022 and 20162021
4
Condensed Consolidated Statement of Comprehensive Income (Unaudited) for the Three and Nine Months Ended September 30, 2017 and 2016
5
Condensed Consolidated Statement of Cash Flows (Unaudited) for the NineThree Months Ended September 30, 2017March 31, 2022 and 20162021
65
Condensed Consolidated Statement of Stockholders' Equity (Unaudited) for the Three Months Ended March 31, 2022 and 2021
6
Notes to the Condensed Consolidated Financial Statements (Unaudited)
7
Item 2.
2119
Item 3.
3229
Item 4.
3331
Item 1.
3433
Item 1A.
3433
Item 2.
34
Item 6.
3435
3537

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Table of Contents
PART I. FINANCIAL INFORMATION
ITEM 1.Financial Statements
CABOT OIL & GAS CORPORATIONCOTERRA ENERGY INC.
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In thousands, except share amounts) September 30,
2017		 December 31,
2016
(In millions, except per share amounts)(In millions, except per share amounts)March 31,
2022		December 31,
2021
ASSETS  
  
ASSETS  
Current assets  
  
Current assets  
Cash and cash equivalents $510,256
 $498,542
Cash and cash equivalents$1,447 $1,036 
Restricted cashRestricted cash10 10 
Accounts receivable, net 161,690
 191,045
Accounts receivable, net1,094 1,037 
Income taxes receivable 26,963
 10,298
Inventories 12,997
 13,304
Inventories41 39 
Other current assets 6,123
 2,692
Other current assets5 14 
Total current assets 718,029
 715,881
Total current assets2,597 2,136 
Properties and equipment, net (Successful efforts method) 4,234,772
 4,250,125
Properties and equipment, net (Successful efforts method)17,346 17,375 
Equity method investments 148,920
 129,524
Other assets 27,045
 27,039
Other assets384 389 
 $5,128,766
 $5,122,569
$20,327 $19,900 
LIABILITIES AND STOCKHOLDERS' EQUITY  
  
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITYLIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY  
Current liabilities  
  
Current liabilities  
Accounts payable $160,789
 $168,411
Accounts payable$874 $747 
Current portion of long-term debt 237,000
 —
Current portion of long-term debt25 — 
Accrued liabilities 27,314
 21,492
Accrued liabilities209 260 
Income taxes payableIncome taxes payable153 29 
Interest payable 12,331
 27,650
Interest payable26 25 
Derivative instruments 800
 40,259
Derivative instruments372 159 
Total current liabilities 438,234
 257,812
Total current liabilities1,659 1,220 
Long-term debt, net 1,284,551
 1,520,530
Long-term debt, net3,090 3,125 
Deferred income taxes 638,014
 579,447
Deferred income taxes3,138 3,101 
Asset retirement obligations 59,605
 131,733
Asset retirement obligations262 259 
Postretirement benefits 27,360
 36,259
Other liabilities 36,408
 29,121
Other liabilities410 407 
Total liabilities 2,484,172
 2,554,902
Total liabilities8,559 8,112 
    
Commitments and contingencies 
 
Commitments and contingencies00
    
Cimarex redeemable preferred stockCimarex redeemable preferred stock5050
Stockholders' equity  
  
Stockholders' equity
Common stock:  
  
Common stock:  
Authorized — 960,000,000 shares of $0.10 par value in 2017 and 2016, respectively  
  
Issued — 475,443,335 shares and 475,042,692 shares in 2017 and 2016, respectively 47,544
 47,504
Authorized — 1,800,000,000 shares of $0.10 par value in 2022 and 2021, respectivelyAuthorized — 1,800,000,000 shares of $0.10 par value in 2022 and 2021, respectively  
Issued — 893,450,009 shares and 892,612,010 shares in 2022 and 2021, respectivelyIssued — 893,450,009 shares and 892,612,010 shares in 2022 and 2021, respectively8989
Additional paid-in capital 1,738,656
 1,727,310
Additional paid-in capital10,927 10,911 
Retained earnings 1,230,002
 1,098,703
Retained earnings2,715 2,563 
Accumulated other comprehensive income 3,482
 985
Accumulated other comprehensive income5 1 
Less treasury stock, at cost:  
  
Less treasury stock, at cost:  
12,935,926 and 9,892,680 shares in 2017 and 2016, respectively (375,090) (306,835)
86,710,998 shares and 79,082,385 shares in 2022 and 2021, respectively86,710,998 shares and 79,082,385 shares in 2022 and 2021, respectively(2,018)(1,826)
Total stockholders' equity 2,644,594
 2,567,667
Total stockholders' equity11,718 11,738 
 $5,128,766
 $5,122,569
 $20,327 $19,900 
The accompanying notes are an integral part of these condensed consolidated financial statements.

3
CABOT OIL & GAS CORPORATION
Table of Contents
COTERRA ENERGY INC.
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
(In thousands, except per share amounts) 2017 2016 2017 2016
OPERATING REVENUES  
  
  
  
   Natural gas $323,319
 $260,200
 $1,152,089
 $711,010
   Crude oil and condensate 56,913
 37,777
 144,528
 114,610
   Gain (loss) on derivative instruments (836) 6,904
 46,353
 (1,286)
   Brokered natural gas 3,528
 3,641
 12,260
 9,417
   Other 2,492
 1,907
 8,486
 5,435
  385,416
 310,429
 1,363,716
 839,186
OPERATING EXPENSES  
  
  
  
   Direct operations 26,282
 24,626
 78,185
 77,139
   Transportation and gathering 117,891
 105,671
 361,909
 322,883
   Brokered natural gas 2,797
 2,939
 10,262
 7,526
   Taxes other than income 9,194
 8,771
 26,562
 23,737
   Exploration 6,466
 2,988
 16,623
 13,109
   Depreciation, depletion and amortization 146,267
 139,490
 425,689
 448,910
   Impairment of oil and gas properties —
 —
 68,555
 —
   General and administrative 23,244
 19,374
 70,902
 67,192
  332,141
 303,859
 1,058,687
 960,496
Earnings (loss) on equity method investments (1,417) (1,727) (3,986) 208
Loss on sale of assets (11,872) (1,245) (13,498) (768)
INCOME (LOSS) FROM OPERATIONS 39,986
 3,598
 287,545
 (121,870)
Interest expense, net 20,331
 21,483
 61,720
 67,821
Loss on debt extinguishment —
 —
 —
 4,709
Other expense (income) (5,083) 402
 (4,974) 1,207
Income (loss) before income taxes 24,738
 (18,287) 230,799
 (195,607)
Income tax expense (benefit) 7,151
 (8,027) 85,965
 (71,243)
NET INCOME (LOSS) $17,587
 $(10,260) $144,834
 $(124,364)
         
Earnings (loss) per share  
  
  
  
Basic $0.04
 $(0.02) $0.31
 $(0.27)
Diluted $0.04
 $(0.02) $0.31
 $(0.27)
         
Weighted-average common shares outstanding  
  
  
  
Basic 462,498
 465,149
 464,194
 454,060
Diluted 464,780
 465,149
 466,010
 454,060
         
Dividends per common share $0.05
 $0.02
 $0.12
 $0.06
 Three Months Ended 
March 31,
(In millions, except per share amounts)20222021
OPERATING REVENUES  
Natural gas$1,111 $473 
Oil699 — 
NGL245 — 
Loss on derivative instruments(391)(13)
Other15 — 
 1,679 460 
OPERATING EXPENSES  
Direct operations100 17 
Transportation, processing and gathering233 137 
Taxes other than income76 5 
Exploration6 3 
Depreciation, depletion and amortization360 94 
General and administrative107 29 
 882 285 
Gain on sale of assets2 — 
INCOME FROM OPERATIONS799 175 
Interest expense, net21 12 
Income before income taxes778 163 
Income tax expense170 37 
NET INCOME$608 $126 
Earnings per share  
Basic$0.75 $0.32 
Diluted$0.74 $0.31 
Weighted-average common shares outstanding  
Basic810 399 
Diluted814 402 
The accompanying notes are an integral part of these condensed consolidated financial statements.

4
CABOT OIL & GAS CORPORATION
Table of Contents
COTERRA ENERGY INC.
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOMECASH FLOWS (Unaudited)
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
(In thousands) 2017 2016 2017 2016
Net income (loss) $17,587
 $(10,260) $144,834
 $(124,364)
Postretirement benefits:        
Net gain (loss) (1)
 (1,429) —
 (1,429) —
Prior service credit (2)
 5,449
 —
 5,449
 —
Amortization of prior service cost (3)
 (1,551) 17
 (1,523) 52
Amortization of (gain) net loss (4)
 287
 —
 —
 —
Total other comprehensive income 2,756
 17
 2,497
 52
Comprehensive income (loss) $20,343
 $(10,243) $147,331
 $(124,312)

(1)
Net of income taxes of $837 for the three and nine months ended September 30, 2017.
(2)
Net of income taxes of $(3,194) for the three months and nine months ended September 30, 2017.
(3)
Net of income taxes of $909 and $(10) for the three months ended September 30, 2017 and 2016, respectively, and $893 and $(31) for the nine months ended September 30, 2017 and 2016, respectively.
(4)
Net of income taxes of $(168) for the three months ended September 30, 2017.

 Three Months Ended 
March 31,
(In millions)20222021
CASH FLOWS FROM OPERATING ACTIVITIES  
  Net income$608 $126 
  Adjustments to reconcile net income to cash provided by operating activities:  
Depreciation, depletion and amortization360 94 
Deferred income tax expense36 12 
Gain on sale of assets(2)— 
Loss on derivative instruments391 13 
Net cash (paid) received in settlement of derivative instruments(171)3 
Amortization of premium and debt issuance costs(10)1 
Stock-based compensation and other20 11 
  Changes in assets and liabilities:  
Accounts receivable, net(57)17 
Income taxes124 24 
Inventories(2)(1)
Other current assets2 1 
Accounts payable and accrued liabilities21 4 
Interest payable1 (13)
Other assets and liabilities1 (2)
Net cash provided by operating activities1,322 290 
CASH FLOWS FROM INVESTING ACTIVITIES  
Capital expenditures(271)(123)
Proceeds from sale of assets2 — 
Net cash used in investing activities(269)(123)
CASH FLOWS FROM FINANCING ACTIVITIES  
Repayments of debt— (88)
Repayments of finance leases(2)— 
Share repurchases(184)— 
Dividends paid(456)(40)
Cash received for stock option exercises6 — 
Tax withholdings on vesting of stock awards(6)(6)
Net cash used in financing activities(642)(134)
Net increase in cash, cash equivalents and restricted cash411 33 
Cash, cash equivalents and restricted cash, beginning of period1,046 152 
Cash, cash equivalents and restricted cash, end of period$1,457 $185 
The accompanying notes are an integral part of these condensed consolidated financial statements.

5
CABOT OIL & GAS CORPORATION
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COTERRA ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWSSTOCKHOLDERS' EQUITY (Unaudited)
(In millions, except per share amounts)Common SharesCommon Stock ParTreasury SharesTreasury StockPaid-In CapitalAccumulated Other Comprehensive IncomeRetained EarningsTotal
Balance at December 31, 2021893 $89 79 $(1,826)$10,911 $1 $2,563 $11,738 
Net income— — — — — — 608608
Exercise of stock options— — — — 6 — — 6 
Stock amortization and vesting— — — — 10 — — 10 
Share repurchases— — 8 (192)— — — (192)
Cash dividends:
Common stock at $0.56 per share— — — — — — (455)(455)
Preferred stock at $20.3125 per share— — — — — — (1)(1)
Other comprehensive income— — — — — 4 — 4 
Balance at March 31, 2022893 $89 87 $(2,018)$10,927 $5 $2,715 $11,718 
  Nine Months Ended 
 September 30,
(In thousands) 2017 2016
CASH FLOWS FROM OPERATING ACTIVITIES  
  
  Net income (loss) $144,834
 $(124,364)
  Adjustments to reconcile net income (loss) to cash provided by operating activities:  
  
Depreciation, depletion and amortization 425,689
 448,910
Impairment of oil and gas properties 68,555
 —
Deferred income tax expense (benefit) 89,731
 (59,413)
Loss on sale of assets 13,498
 768
Exploratory dry hole cost 2,842
 18
(Gain) loss on derivative instruments (46,353) 1,286
Net cash received in settlement of derivative instruments 3,587
 3,204
(Earnings) loss on equity method investments 3,986
 (208)
Amortization of debt issuance costs 3,579
 3,888
Stock-based compensation and other 26,011
 23,051
  Changes in assets and liabilities:  
  
Accounts receivable, net 29,276
 (1,135)
Income taxes (16,665) (11,235)
Inventories (2,100) 2,860
Other current assets (896) (917)
Accounts payable and accrued liabilities (5,133) (12,174)
Interest payable (15,318) (17,618)
Other assets and liabilities (6,076) 784
Net cash provided by operating activities 719,047
 257,705
CASH FLOWS FROM INVESTING ACTIVITIES  
  
Capital expenditures (586,813) (245,033)
Proceeds from sale of assets 32,711
 49,068
Investment in equity method investments (23,382) (24,176)
Net cash used in investing activities (577,484) (220,141)
CASH FLOWS FROM FINANCING ACTIVITIES  
  
Borrowings from debt —
 90,000
Repayments of debt —
 (587,000)
Treasury stock repurchases (68,255) —
Sale of common stock, net —
 995,279
Dividends paid (55,707) (26,885)
Tax withholdings on stock award vestings (5,929) (5,056)
Capitalized debt issuance costs —
 (3,223)
Other 42
 —
Net cash provided by (used in) financing activities (129,849) 463,115
Net increase in cash and cash equivalents 11,714
 500,679
Cash and cash equivalents, beginning of period 498,542
 514
Cash and cash equivalents, end of period $510,256
 $501,193

(In millions, except per share amounts)Common SharesCommon Stock ParTreasury SharesTreasury StockPaid-In CapitalAccumulated Other Comprehensive IncomeRetained EarningsTotal
Balance at December 31, 2020478 $48 79 $(1,823)$1,804 $2 $2,185 $2,216 
Net income— — — — — — 126 126 
Stock amortization and vesting— — — — 4 — — 4 
Cash dividends at $0.10 per share— — — — — — (40)(40)
Balance at March 31, 2021478 $48 79 $(1,823)$1,808 $2 $2,271 $2,306 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION
COTERRA ENERGY INC.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. Financial Statement Presentation
During interim periods, Cabot Oil & Gas CorporationCoterra Energy Inc. (the Company)“Company”) follows the same accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2016 (Form 10-K)2021 (the “Form 10-K”) filed with the Securities and Exchange Commission (SEC).(“SEC”), except for any new accounting pronouncements adopted during the period. The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the results that may be expected results for the entire year.
Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications hadhave no impact on previously reported stockholders' equity, net income (loss) or cash flows, except as discussedflows.
2. Acquisitions
Cimarex Energy Co.
On October 1, 2021, the Company completed a merger transaction (the “Merger”) with Cimarex Energy Co. (“Cimarex”). Cimarex is an oil and gas exploration and production company with operations in "Recently Adopted Accounting Pronouncements" below.Texas, New Mexico and Oklahoma.
Recently Adopted Accounting PronouncementsPurchase Price Allocation
Stock-Based Compensation. In March 2016,The transaction was accounted for using the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting, as an amendment to Accounting Standards Codification (ASC) Topic 718. The areas for simplification in this update involve several aspectsacquisition method of accounting. Under the acquisition method of accounting, for share-based payment transactions, including the income tax consequences, forfeitures, classification of awards as either equity orassets, liabilities and classification on the statementmezzanine equity of cash flows. The guidance is effective for interimCimarex and annual periods beginning after December 15, 2016. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equityits subsidiaries were recorded at their respective fair values as of the beginningeffective date of the period inMerger. The purchase price allocation was based on preliminary estimates and assumptions, which are subject to change for up to one year after October 1, 2021, the guidance is adopted. Amendments related toeffective date of the presentationMerger, as the Company finalizes the valuations of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statementassets acquired, liabilities assumed and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company elected to apply this guidance on a prospective basis.
The Company adopted this guidance effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits resulted in a cumulative-effect adjustment of $42.2 million, which increased retained earnings and decreased net deferred tax liabilities by the same amountbalances as of the beginning of 2017. Effective January 1, 2017, cash paid by the Company when directly withholding shares from employee awards for tax-withholding purposes will be classified as a financing activity. This change has been recognized retrospectively beginning January 1, 2015. Prior periods have been adjusted as follows:
  Net Cash Provided by Operating Activities Net Cash Provided by Financing Activities
(In thousands) As Reported As Adjusted As Reported As Adjusted
Year ended December 31, 2015 $740,737
 $749,598
 $232,157
 $223,296
Three months ended March 31, 2016 62,090
 67,112
 570,773
 565,751
Six months ended June 30, 2016 147,244
 152,290
 497,474
 492,428
Nine months ended September 30, 2016 252,649
 257,705
 468,171
 463,115
Year ended December 31, 2016 392,377
 397,441
 458,869
 453,805
The remaining provisions of this amendment did not have a material effect on the Company's financial position, results of operations or cash flows.
Accounting Changes and Error Corrections. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a descriptioneffective date of the effectMerger. Determining the fair value of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately. The Company adopted this guidance during the first quarter of 2017. The adoption of this guidance impacted the Company's disclosures but had no effect on its financial position, results of operations or cash flows.

Retirement Benefits. In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715). The amendments in this update require that an employer report the service cost component of postretirement benefits in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in this update also allow only the service cost component to be eligible for capitalization when applicable. The amendments in this update should be applied retrospectively for the presentation of the service cost component and the other components of net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic benefit cost in assets.
The guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. The Company elected to early adopt this guidance effective January 1, 2017. The reclassification of interest and amortization of prior service cost resulted in an increase in operating income and an increase in other expense (non-operating expense) of $1.6 million and $1.4 million for the years ended December 31, 2016 and 2015, respectively, and $1.2 million for the nine months ended September 30, 2016.
Recently Issued Accounting Pronouncements
Financial Instruments. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall, as an amendment to ASC Subtopic 825-10. The amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Among other items, this update will simplify the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment. When a qualitative assessment indicates that impairment exists, an entity is required to measure the investment at fair value. This impairment assessment reduces the complexity of the other-than-temporary impairment guidance that entities follow currently. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption of this amendment is not permitted. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operation or cash flows.
Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, as a new Topic, ASC Topic 842. The new lease guidance supersedes Topic 840. The core principle of the guidance is that a company should recognize the assets and liabilities that arise from leases. This ASU does not apply to leases to explore for or use minerals, oil, natural gasof Cimarex requires judgment and similar nonregenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. The guidance is effective for interim and annual periods beginning after December 15, 2018. This ASU iscertain assumptions to be adoptedmade. The most significant fair value estimates related to the valuation of Cimarex's oil and gas properties and certain other fixed assets, long-term debt and derivative instruments. Oil and gas properties and certain fixed assets were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates. Long-term debt was valued using a modified retrospective approach. The Company plansmarket approach utilizing Level 1 inputs including observable market prices on the underlying debt instruments. Derivative liabilities were based on Level 3 inputs consistent with the Company’s other commodity derivative instruments. There were no adjustments to adopt this guidance effective January 1, 2019 and is currently evaluating the effect that adopting this guidance will have on its financial position,purchase price allocation during the three months ended March 31, 2022.
Unaudited Pro Forma Financial Information
The results of Cimarex’s operations or cash flows.
Revenue Recognition. In May 2014,have been included in the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, ASC Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferredCompany’s consolidated financial statements since October 1, 2021, the effective date of ASU No. 2014-09 by one year, making the new standard effectiveMerger. The following supplemental pro forma information for interim and annual periods beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption.
Additionally, inthree months ended March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related31, 2021 has been prepared to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvements and practical expedients, which addresses narrow-scope improvementsgive effect to the guidance on collectibility, non-cash consideration, and completed contracts at transition. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which clarifies the guidance or corrects unintended application of guidance.

The Company plans to adopt this guidance effective January 1, 2018 using the modified retrospective method applied to contracts that are not completedCimarex acquisition as of that date. To date, the Company has not identified changes to its revenue recognition policies that would result in a material adjustment to the opening balance of retained earningsif it had occurred on January 1, 2018; however, it is continuing to evaluate the effect, if any,2021. The information below reflects pro forma adjustments based on available information and certain assumptions that adopting this guidance will have on its financial position,Coterra believes are factual and supportable. The pro forma results of operations do not include any cost savings or cash flows. other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Coterra to integrate the Cimarex assets.
The Companypro forma information is also evaluating its agreements with royaltynot necessarily indicative of the results that might have occurred had the transaction actually taken place on January 1, 2021 and nonoperated partners for principal versus agent consideration. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue. As allowed under Topic 606, the Company doesis not plan to disclose the value of unsatisfied performance obligations for contracts with variable consideration or with an original term of one year or less.
Statement of Cash Flows.In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), which is intended to reduce diversity in practice in how certain transactions are classifiedbe a projection of future results. Future results may vary significantly
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from the results reflected in the statementfollowing pro forma information because of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017normal production declines, changes in commodity prices, future acquisitions and interim periods within those annual periods. Early adoption is permitted, provided that all of the amendments are adopted in the same period. This ASU must be adopted using a retrospective transition method.divestitures, future development and exploration activities and other factors.
Upon adopting this guidance, the Company will be required to make an accounting policy election to classify distributions it receives from its equity method investees under either (1) the cumulative earnings approach in which distributions received are considered returns on investment and classified as cash inflows from operating activities unless the cumulative distributions received exceed cumulative equity in earnings recognized by the Company, or (2) the nature of distributions approach in which distributions received are classified on the basis of the nature of the activity that generated the distribution as either a return on investment (cash inflows from operating activities) or a return of investment (cash inflows from investing activities). The Company has not yet determined which policy election it will make. Currently, the Company is not receiving any distributions from its equity method investees; therefore, the selection between the policy elections would not have a material effect on its presentation of cash flows. If material distributions are received in the future, the impact of the policy election could be material. The Company expects to adopt this guidance effective January 1, 2018 and is currently evaluating the effect that adopting the remaining areas of this guidance will have on its presentation of cash flows. Adoption of this guidance is not expected to have a material effect on the Company's financial position or results of operations.
(In millions, except per share information)Three Months Ended 
March 31, 2021
Pro forma revenue$978 
Pro forma net income79 
Pro forma basic earnings per share$0.10 
Pro forma diluted earnings per share$0.10 

2.
3. Properties and Equipment, Net
Properties and equipment, net are comprised of the following:
(In millions)March 31,
2022		December 31,
2021
Proved oil and gas properties$15,653 $15,340 
Unproved oil and gas properties5,317 5,316 
Pipelines and gathering402 395 
Land, buildings and other equipment140 140 
Finance lease right-of-use asset24 20 
21,536 21,211 
Accumulated depreciation, depletion and amortization(4,190)(3,836)
 $17,346 $17,375 
Capitalized Exploratory Well Costs
(In thousands) September 30,
2017		 December 31,
2016
Proved oil and gas properties $6,967,205
 $7,437,604
Unproved oil and gas properties 287,147
 260,543
Gathering and pipeline systems 1,451
 187,846
Land, building and other equipment 88,371
 84,462
  7,344,174
 7,970,455
Accumulated depreciation, depletion and amortization (3,109,402) (3,720,330)
  $4,234,772
 $4,250,125
Proved oil and gas properties, gathering and pipeline systems and accumulated depreciation, depletion and amortization decreased from DecemberAs of March 31, 2016 to September 30, 2017 primarily as a result of the sale of assets in West Virginia, Virginia and Ohio discussed below.
At September 30, 2017,2022, the Company did not have any projects that hadwith exploratory well costs capitalized for a period of greater than one year after drilling.
Divestitures
In September 2017, the Company sold certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio for $41.3 million, subject to customary purchase price adjustments. During the second quarter of 2017, the Company classified these assets as held for sale and recorded an impairment charge of $68.6 million associated with the proposed sale of these properties. Upon closing the sale in the third quarter of 2017, the Company recognized a loss on sale of oil and gas properties of $11.9 million.

The fair value of the impaired properties was determined using a market approach that took into consideration the expected sales price included in the purchase and sale agreement the Company executed on June 30, 2017. Accordingly, the inputs associated with the fair value of these assets were considered Level 3 in the fair value hierarchy. Refer to Note 1 of the Notes to the Consolidated Financial Statements in the Form 10-K for a description of the fair value hierarchy.
In February 2016, the Company completed the divestiture of certain proved and unproved oil and gas properties in east Texas for approximately $56.4 million resulting in a $0.5 million gain on sale of assets.
3. Equity Method Investments
The Company holds a 25% equity interest in Constitution Pipeline Company, LLC (Constitution) and a 20% equity interest in Meade Pipeline Co LLC (Meade). Activity related to these equity method investments is as follows:
  Constitution Meade Total
  Nine Months Ended September 30,
(In thousands) 2017 2016 2017 2016 2017 2016
Balance at beginning of period $96,850
 $90,345
 $32,674
 $13,172
 $129,524
 $103,517
Contributions 3,750
 8,325
 19,632
 15,851
 23,382
 24,176
Earnings (loss) on equity method investments (3,971) 211
 (15) (3) (3,986) 208
Balance at end of period $96,629
 $98,881
 $52,291
 $29,020
 $148,920
 $127,901
During 2017, the Company expects to contribute approximately $70.0 million to its equity method investments. For further information regarding the Company’s equity method investments, refer to Note 4 of the Notes to the Consolidated Financial Statements in the Form 10-K.
Constitution
On April 22, 2016, Constitution announced that the New York State Department of Environmental Conservation (NYSDEC) denied Constitution's application for a Section 401 Water Quality Certification (Certification) for the New York State portion of its proposed 126-mile route. During the second quarter of 2016, Constitution filed legal actions in the U.S. Court of Appeals for the Second Circuit and the U.S. District Court for the Northern District of New York challenging the legality and appropriateness of the NYSDEC’s decision. On March 16, 2017, the U.S. District Court for the Northern District of New York issued an order ruling, without prejudice, that it lacked subject matter jurisdiction to hear Constitution’s complaint.  On August 18, 2017, the Second Circuit issued a decision denying in part and dismissing in part Constitution’s appeal.  The Second Circuit determined that it lacked jurisdiction to address Constitution’s argument that the NYSDEC waived its ability to issue a Certification by unreasonably delaying action on Constitution's application.  Instead, the Second Circuit found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit.  The Second Circuit, however, rejected Constitution’s assertion that the denial of the Certification by the NYSDEC was “arbitrary and capricious” and denied Constitution’s complaint in that regard. On October 11, 2017, Constitution filed a petition for a declaratory order requesting the Federal Energy Regulatory Commission (FERC) to find that, by operation of law, the Section 401 Water Quality Certification requirement for the New York State portion of the pipeline project was waived due to the failure of the NYSDEC to act on Constitution’s application within a reasonable period of time, as required by the Clean Water Act.  The FERC has not yet ruled on this petition.
Constitution stated that it remains committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC’s decision. In light of the current status of the litigation and the regulatory challenges, Constitution estimates its target in-service date to be as early as the first half of 2019. This assumes the timely receipt of a notice to proceed from the FERC and the timely receipt of all other state and federal permits required for the project. 
In light of the NYSDEC’s denial and actions taken to challenge the denial, the Company evaluated its investment in Constitution for other-than-temporary impairment (OTTI) as of September 30, 2017 and does not believe there is an indication of an OTTI. The Company’s evaluation considered various factors, including but not limited to prior FERC approval and the related economic viability of the project, the pending legal and regulatory actions filed by Constitution and the other members’ commitment to the project. To the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is no longer viable or elects to not go forward as legal and regulatory actions progress, the Company will reevaluate the facts and circumstances relative to its conclusions with respect to OTTI. In the event that facts and circumstances change, the Company may be required to recognize an impairment charge up to its investment value at such time, net of any cash and working capital held by Constitution. The Company will continue to monitor the carrying value of its investment as required.

At this time, the Company remains committed to funding the project in an amount proportionate to its ownership interest for the development and construction of the new pipeline. As of September 30, 2017, the Company has made contributions of $92.3 million since inception of the project.
4. Debt and Credit Agreements
The Company’s debt and credit agreements consisted of the following:
(In millions)March 31,
2022		December 31,
2021
Total debt
6.51% weighted-average private placement senior notes$37 $37 
5.58% weighted-average private placement senior notes (1)
87 87 
3.65% weighted-average private placement senior notes825 825 
4.375% senior notes due June 1, 2024750 750 
3.90% senior notes due May 15, 2027750 750 
4.375% senior notes due March 15, 2029500 500 
Revolving credit facility— — 
Net premium (discount)175 185 
Unamortized debt issuance costs(9)(9)
$3,115 $3,125 

(In thousands) September 30,
2017		 December 31,
2016
Total debt    
6.51% weighted-average senior notes $361,000
 $361,000
9.78% senior notes 67,000
 67,000
5.58% weighted-average senior notes 175,000
 175,000
3.65% weighted-average senior notes 925,000
 925,000
Current maturities    
6.51% weighted-average senior notes (237,000) —
Long-term debt, excluding current maturities $1,291,000
 $1,528,000
Unamortized debt issuance costs (6,449) (7,470)
  $1,284,551
 $1,520,530
The borrowing base under the terms(1) Includes $25 million of the Company's revolving credit facility is redetermined annuallycurrent portion of long-term debt at March 31, 2022 due in April. In addition, either the Company or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. Effective April 11, 2017, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively.January 2023.
At September 30, 2017,March 31, 2022, the Company was in compliance with all restrictive financial and other covenants for both its revolving credit facility and senior notes. As
8
Table of September 30, 2017, based on the Company's asset coverage and leverage ratios, there were no interest rate adjustments required for the Company's senior notes.Contents
Revolving Credit Agreement
At September 30, 2017,March 31, 2022, the Company had no borrowings outstanding under its revolving credit facility and had unused commitments of $1.7$1.5 billion. The Company’s weighted-average effective interest rate for the revolving credit facility for the nine months ended September 30, 2016 was approximately 2.3%.
5. Derivative Instruments and Hedging Activities
As of September 30, 2017,March 31, 2022, the Company had the following outstanding financial commodity derivatives:
Collars
   FloorCeiling
Type of ContractVolume (Mmbtu)Contract PeriodRange
($/Mmbtu)		Weighted-Average
($/Mmbtu)		Range
($/Mmbtu)		Weighted-Average
($/Mmbtu)
Natural gas (NYMEX)74,900,000Apr. 2022 - Oct. 2022$3.00 - $4.50$3.61 $4.07 - $6.68$5.12 
Natural gas (Perm EP)(1)
1,820,000Apr. 2022 - Jun. 2022$— $2.40 $2.85 - $2.90$2.88 
Natural gas (Perm EP)(1)
5,500,000Apr. 2022 - Dec. 2022$— $2.50 $— $3.15 
Natural gas (PEPL)(2)
1,820,000Apr. 2022 - Jun. 2022$— $2.40 $2.81 - $2.91$2.86 
Natural gas (PEPL)(2)
5,500,000Apr. 2022 - Dec. 2022$— $2.60 $— $3.27 
Natural gas (Waha)(3)
1,820,000Apr. 2022 - Jun. 2022$— $2.40 $2.82 - $2.89$2.86 
Natural gas (Waha)(3)
1,830,000Apr. 2022 - Sep. 2022$— $2.40 $— $2.77 
Natural gas (Waha)(3)
5,500,000Apr. 2022 - Dec. 2022$— $2.50 $— $3.12 
Natural gas (NYMEX)71,500,000Apr. 2022 - Dec 2022$3.50 - $4.25$3.84 $4.75 - $6.60$5.39 
Natural gas (NYMEX)52,850,000Nov 2022 - Mar 2023$4.00 - $4.75$4.46 $7.00 - $10.10$8.37 
________________________________________________________
(1)The index price is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.
(2)The index price is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.
(3)The index price is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.
Collars
FloorCeilingBasis SwapsRoll Swaps
Type of ContractVolume (Mbbl)Contract PeriodRange
($/Bbl)		Weighted-Average
($/Bbl)		Range
($/Bbl)		Weighted-Average
($/Bbl)		Weighted-Average
($/Bbl)		Weighted-Average
($/Bbl)
Crude oil (WTI)819Apr. 2022-Jun. 2022$35.00 - $37.50$36.11 $48.38 - $51.10$49.97 
Crude oil (WTI)1,830Apr. 2022-Sep. 2022$— $40.00 $47.55 - $50.89$49.19 
Crude oil (WTI)2,200Apr. 2022-Dec. 2022$— $57.00 $72.20 - $72.80$72.43 
Crude oil (WTI Midland)(1)
728Apr. 2022-Jun. 2022$0.25 
Crude oil (WTI Midland)(1)
1,281Apr. 2022-Sep. 2022$0.38 
Crude oil (WTI Midland)(1)
2,200Apr. 2022-Dec. 2022$0.05 
Crude oil (WTI)364Apr. 2022-Jun. 2022$(0.20)
Crude oil (WTI)1,281Apr. 2022-Sep. 2022$0.10 

(1)The index price is WTI Midland as quoted by Argus Americas Crude.
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       Collars   Basis Swaps
       Floor Ceiling Swaps 
Type of Contract Volume Contract Period Range Weighted-Average Range Weighted-Average Weighted-Average Weighted-Average
Natural gas - NYMEX 8.9
Bcf Oct. 2017 - Dec. 2017         $3.12
  
Natural gas - TCO 4.5
Bcf Oct. 2017 - Dec. 2017         $3.46
  
Natural gas - NYMEX 8.9
Bcf Oct. 2017 - Dec. 2017 $—
 $3.09
 $3.42-$3.45 $3.43
    
Natural gas - Transco 21.3
Bcf Jan. 2018 - Dec. 2019           $0.42
Crude oil 0.5
Mmbbl Oct. 2017 - Dec. 2017 $—
 $50.00
 $56.25-$56.50 $56.39
    
Subsequent event. In April 2022, the Company entered into the following financial commodity derivatives:
In the table above, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.
   Swaps
Type of ContractVolume (Mmbtu)Contract PeriodWeighted-Average
($/Mmbtu)
Natural gas (Waha)(1)
9,200,000 May 2022 - Oct 2022$4.77 

(1)The index price is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.


Collars
FloorCeilingBasis Swaps
Type of ContractVolume (Mbbl)Contract PeriodRange
($/Bbl)		Weighted-Average
($/Bbl)		Range
($/Bbl)		Weighted-Average
($/Bbl)		Weighted-Average
($/Bbl)
Crude oil (WTI)920Oct. 2022 - Dec. 2022$— $65.00 $136.25 - $145.25$140.49 
Crude oil (WTI)1,810Jan. 2023 - Jun 2023$— $65.00 $116.30 - $118.30$117.47 
Crude oil (WTI Midland)(1)
920Oct. 2022 - Dec. 2022$0.64 
Crude oil (WTI Midland)(1)
1,810Jan. 2023 - Jun 2023$0.64 

(1)The index price is WTI Midland as quoted by Argus Americas Crude.

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet
 Derivative AssetsDerivative Liabilities
(In millions)(In millions)Balance Sheet LocationMarch 31,
2022		December 31,
2021		March 31,
2022		December 31,
2021
Commodity contractsCommodity contractsDerivative instruments (current)$— $7 $372 $159 
   Derivative Assets Derivative Liabilities$— $7 $372 $159 
(In thousands) Balance Sheet Location September 30,
2017		 December 31,
2016		 September 30,
2017		 December 31,
2016
Commodity contracts Other current assets $2,536
 $—
 $—
 $—
Commodity contracts Other assets (non-current) 3,763
 2,991
 —
 —
Commodity contracts Derivative instruments (current) —
 —
 800
 40,259
   $6,299
 $2,991
 $800
 $40,259
Offsetting of Derivative Assets and Liabilities in the Condensed Consolidated Balance Sheet
(In millions)March 31,
2022		December 31,
2021
Derivative assets  
Gross amounts of recognized assets$— $27 
Gross amounts offset in the condensed consolidated balance sheet— (20)
Net amounts of assets presented in the condensed consolidated balance sheet— 7 
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet— — 
Net amount$— $7 
Derivative liabilities  
Gross amounts of recognized liabilities$372 $179 
Gross amounts offset in the condensed consolidated balance sheet— (20)
Net amounts of liabilities presented in the condensed consolidated balance sheet372 159 
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet58 35 
Net amount$314 $194 
10
(In thousands) September 30,
2017		 December 31,
2016
Derivative assets  
  
Gross amounts of recognized assets $6,605
 $2,991
Gross amounts offset in the statement of financial position (306) —
Net amounts of assets presented in the statement of financial position 6,299
 2,991
Gross amounts of financial instruments not offset in the statement of financial position 18
 —
Net amount $6,317
 $2,991
     
Derivative liabilities  
  
Gross amounts of recognized liabilities $1,106
 $40,259
Gross amounts offset in the statement of financial position (306) —
Net amounts of liabilities presented in the statement of financial position 800
 40,259
Gross amounts of financial instruments not offset in the statement of financial position —
 757
Net amount $800
 $41,016
Table of Contents
Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations
 Three Months Ended 
March 31,
(In millions)20222021
Cash received (paid) on settlement of derivative instruments  
Gas Contracts$(42)$3 
Oil Contracts(129)— 
Non-cash loss on derivative instruments  
Gas Contracts(182)(16)
Oil Contracts(38)— 
 $(391)$(13)
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
(In thousands) 2017 2016 2017 2016
Cash received (paid) on settlement of derivative instruments  
  
  
  
Gain (loss) on derivative instruments $3,906
 $(8,101) $3,587
 $3,204
Non-cash gain (loss) on derivative instruments  
  
  
  
Gain (loss) on derivative instruments (4,742) 15,005
 42,766
 (4,490)
  $(836) $6,904
 $46,353
 $(1,286)
6. Fair Value Measurements
The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. For further information regarding the fair value hierarchy, refer to Note 1 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Financial Assets and Liabilities
The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis:
(In millions)Quoted Prices in
Active Markets for
Identical Assets
(Level 1)		Significant Other
Observable Inputs
(Level 2)		Significant
Unobservable Inputs
(Level 3)		Balance at  
March 31, 2022
Assets    
Deferred compensation plan$46 $— $— $46 
Derivative instruments— — — — 
$46 $— $— $46 
Liabilities   
Deferred compensation plan$60 $— $— $60 
Derivative instruments— — 372 372 
$60 $— $372 $432 
(In thousands) 
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Unobservable Inputs
(Level 3)
 Balance at  
 September 30, 2017
Assets  
  
  
  
Deferred compensation plan $14,336
 $—
 $—
 $14,336
Derivative instruments —
 —
 6,605
 6,605
     Total assets $14,336
 $—
 $6,605
 $20,941
Liabilities    
  
  
Deferred compensation plan $27,598
 $—
 $—
 $27,598
Derivative instruments —
 178
 928
 1,106
     Total liabilities $27,598
 $178
 $928
 $28,704
(In thousands) 
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Unobservable Inputs
(Level 3)
 Balance at  
 December 31, 2016
(In millions)(In millions)Quoted Prices in
Active Markets for
Identical Assets
(Level 1)		Significant Other
Observable Inputs
(Level 2)		Significant
Unobservable Inputs
(Level 3)		Balance at  
December 31, 2021
Assets  
  
  
  
Assets    
Deferred compensation plan $12,587
 $—
 $—
 $12,587
Deferred compensation plan$47 $— $— $47 
Derivative instruments —
 —
 2,991
 2,991
Derivative instruments— — 27 27 
Total assets $12,587
 $—
 $2,991
 $15,578
$47 $— $27 $74 
Liabilities    
  
  
Liabilities   
Deferred compensation plan $24,169
 $—
 $—
 $24,169
Deferred compensation plan$56 $— $— $56 
Derivative instruments��—
 21,400
 18,859
 40,259
Derivative instruments— — 179 179 
Total liabilities $24,169
 $21,400
 $18,859
 $64,428
$56 $— $179 $235 
The Company’sCompany's investments associated with its deferred compensation plan consist of mutual funds and deferred shares of the Company’sCompany's common stock that are publicly traded and for which market prices are readily available.
The derivative instruments were measured based on quotes from the Company’s counterparties.Company's counterparties or internal models. Such quotes and models have been derived using an income approach that considers various inputs, including current market and contractual prices for the underlying instruments, quoted forward commodity prices, for natural gas and crude oil, basis differentials, volatility factors and interest rates such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. Estimates are derived from or verified using relevant NYMEX futures contracts and/orand are compared to multiple quotes obtained from counterparties or other third
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parties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with which it has derivative transactions while non-performance risk of the Company is evaluated using a market credit spreadspreads provided by several of the Company’s bank.Company's banks. The Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.
The most significant unobservable inputs relative to the Company’sCompany's Level 3 derivative contracts are basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
  Nine Months Ended 
 September 30,
(In thousands) 2017 2016
Balance at beginning of period $(15,868) $—
Total gain (loss) included in earnings 28,659
 381
Settlement (gain) loss (7,114) 83
Transfers in and/or out of level 3 —
 —
Balance at end of period $5,677
 $464
     
Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period $14,431
 $464
There were no transfers between Level 1 and Level 2 fair value measurements for the nine months ended September 30, 2017 and 2016.
Three Months Ended 
March 31,
(In millions)20222021
Balance at beginning of period$(152)$24 
Total gain (loss) included in earnings(391)(13)
Settlement (gain) loss171 (3)
Transfers in and/or out of Level 3— — 
Balance at end of period$(372)$8 
Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period$(291)$(6)
Non-Financial Assets and Liabilities
The Company discloses or recognizes its non-financial assets and liabilities, such as impairments or acquisitions, at fair value on a nonrecurring basis. The Company recorded an impairment charge related to certain oil and gas properties during the quarter ended June 30, 2017. Refer to Note 2 of the Notes to the Condensed Consolidated Financial Statements for additional disclosures related to fair value associated with the impaired assets. As none of the Company’s other non-financial assets and liabilities were measured at fair value as of September 30, 2017,March 31, 2022, additional disclosures were not required.
The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.
Fair Value of Other Financial Instruments
The estimated fair value of other financial instruments is the amount at which the instrumentinstruments could be exchanged currently between willing parties. The carrying amountamounts reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents approximatesand restricted cash approximate fair value, due to the short-term maturities of these instruments. Cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy and the remaining financial instruments are classified as Level 2.
The fair value of the Company’s 4.375% senior notes due June 1, 2024, 3.90% senior notes due May 15, 2027 and 4.375% senior notes due March 15, 2029 is based on quoted market prices, which is classified as Level 1 in the fair value hierarchy. The Company uses available market data and valuation methodologies to estimate the fair value of debt.its private placement senior notes. The fair value of debtthe private placement senior notes is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of allthe private placement senior notes and the revolving credit facility is based on interest rates currently available to the Company. The Company’s debt isprivate placement senior notes are valued using an income approach and are classified as Level 3 in the fair value hierarchy.
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The carrying amount and estimated fair value of debt is as follows:
 March 31, 2022December 31, 2021
(In millions)Carrying
Amount		Estimated Fair
Value		Carrying
Amount		Estimated Fair
Value
Long-term debt$3,115 $2,999 $3,125 $3,163 
Current maturities(25)(25)— — 
Long-term debt, excluding current maturities$3,090 $2,974 $3,125 $3,163 
  September 30, 2017 December 31, 2016
(In thousands) 
Carrying
Amount
 
Estimated Fair
Value
 
Carrying
Amount
 
Estimated Fair
Value
Debt, net $1,521,551
 $1,536,360
 $1,520,530
 $1,463,643
Current maturities (237,000) (243,569) —
 —
Long-term debt, excluding current maturities $1,284,551
 $1,292,791
 $1,520,530
 $1,463,643


7. Asset Retirement Obligations
Activity related to the Company’s asset retirement obligations is as follows:
(In millions)Three Months Ended 
March 31, 2022
Balance at beginning of period$263 
Liabilities incurred3 
Liabilities settled(1)
Liabilities divested(2)
Accretion expense2 
Balance at end of period265 
Less: current asset retirement obligations(3)
Noncurrent asset retirement obligations$262 
(In thousands) Nine Months Ended 
 September 30, 2017
Balance at beginning of period $133,733
Liabilities incurred 3,788
Liabilities settled (1,225)
Liabilities divested (75,014)
Accretion expense 4,396
Balance at end of period $65,678
As of September 30, 2017 and December 31, 2016, approximately $6.1 million and $2.0 million, respectively, is included in accrued liabilities in the Condensed Consolidated Balance Sheet, which represents the current portion of the Company's asset retirement obligation.
8. Commitments and Contingencies
Contractual Obligations
The Company has various contractual obligations in the normal course of its operations. There have been no material changes to the Company’s contractual obligations described under “Transportation, Processing and Gathering Agreements,” “Drilling Rig Commitments,”Agreements” and “Lease Commitments” and “Hydraulic Fracturing Services Commitments” as disclosed in Note 9 in8 of the Notes to Consolidated Financial Statements in the Form 10-K.
Legal Matters
Pennsylvania Office of Attorney General Matter
On June 16, 2020, the Office of Attorney General of the Commonwealth of Pennsylvania informed the Company that it will pursue certain misdemeanor and felony charges in a Susquehanna County Magisterial District Court against the Company related to alleged violations of the Pennsylvania Clean Streams Law, which prohibits discharge of industrial wastes. The Company is vigorously defending itself against such charges; however, the proceedings could result in fines or penalties against the Company. At this time, it is not possible to estimate the amount of any fines or penalties, or the range of such fines or penalties, that are reasonably possible in this case.
Securities Litigation
In October 2020, a class action lawsuit styled Delaware County Emp. Ret. Sys. v. Cabot Oil and Gas Corp., et. al. (U.S. District Court, Middle District of Pennsylvania), was filed against the Company, Dan O. Dinges, its then Chief Executive Officer, and Scott C. Schroeder, its Chief Financial Officer, alleging that the Company made misleading statements in its periodic filings with the SEC in violation of Section 10(b) and Section 20 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The plaintiffs allege misstatements in the Company’s public filings and disclosures over a number of years relating to its potential liability for alleged environmental violations in Pennsylvania. The plaintiffs allege that such misstatements caused a decline in the price of the Company’s common stock when it disclosed in its Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019 two notices of violations from the Pennsylvania Department of Environmental Protection and an additional decline when it disclosed on June 15, 2020 the criminal charges brought by the Office of the Attorney General of the Commonwealth of Pennsylvania related to alleged violations of the Pennsylvania Clean Streams Law, which prohibits discharge of industrial wastes. The court appointed Delaware County Employees Retirement System to represent the purported class on February 3, 2021. In April 2021, the complaint was amended to include Phillip L. Stalnaker, the Company’s then Senior Vice President of Operations, as a defendant. The plaintiffs seek monetary damages, interest and attorney’s fees.
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Also in October 2020, a stockholder derivative action styled Ezell v. Dinges, et. al. (U.S. District Court, Middle District of Pennsylvania) was filed against the Company, Messrs. Dinges and Schroeder and the Board of Directors of the Company serving at that time, for alleged securities violations under Section 10(b) and Section 21D of the Exchange Act arising from the same alleged misleading statements that form the basis of the class action lawsuit described above. In addition to the Exchange Act claims, the derivative actions also allege claims based on breaches of fiduciary duty and statutory contribution theories. In December 2020, the Ezell case was consolidated with a second derivative case filed in the U.S. District Court, Middle District of Pennsylvania with similar allegations. In January 2021, a third derivative case was filed in the U.S. District Court, Middle District of Pennsylvania with substantially similar allegations and it too was consolidated with the Ezell case in February 2021.
On February 25, 2021, the Company filed a motion to transfer the class action lawsuit to the U.S. District Court for the Southern District of Texas, in Houston, Texas, where its headquarters are located. On June 11, 2021, the Company filed a motion to dismiss the class action lawsuit on the basis that the plaintiffs’ allegations do not meet the requirements for pleading a claim under Section 10(b) or Section 20 of the Exchange Act. On June 22, 2021, the motion to transfer the class action lawsuit to the Southern District of Texas was granted. Pursuant to the prior agreement of the parties, the consolidated derivative case discussed in the preceding paragraph was also transferred to the Southern District of Texas on July 12, 2021. Subsequently, an additional stockholder derivative action styled Treppel Family Trust U/A 08/18/18 Lawrence A. Treppel and Geri D. Treppel for the benefit of Geri D. Treppel and Larry A. Treppel v. Dinges, et al. (U.S. District Court, Southern District of Texas, Houston Division), asserting substantially similar Delaware common law claims as in the existing derivative cases, was filed in the Southern District of Texas and consolidated with the existing consolidated derivative cases. On January 12, 2022, the U.S. District Court for the Southern District of Texas granted the Company’s motion to dismiss the class action lawsuit but allowed the plaintiffs to file an amended complaint. The class action plaintiffs filed their amended complaint on February 11, 2022. The Company filed a motion to dismiss the amended class action complaint on March 10, 2022, to which the class action plaintiffs filed an opposition on April 13, 2022. On April 1, 2022, the U.S. District Court for the Southern District of Texas granted the Company’s motion to dismiss the consolidated derivative case but allowed the plaintiffs to file an amended complaint. The Company intends to vigorously defend the class action and derivative lawsuits.
In November 2020, the Company received a stockholder demand for inspection of books and records under Section 220 of the General Corporation Law of the State of Delaware (“Section 220 Demand”). The Section 220 Demand seeks broad categories of documents reviewed by the Board of Directors and minutes of meetings of the Board of Directors pertaining to alleged environmental violations in Pennsylvania, as well as documents relating to any board of directors conflicts of interest, dating from January 1, 2015 to the present. The Company also received three other similar requests from other stockholders in February and June 2021. On May 17, 2021, the Company was served with a complaint filed in the Court of Chancery of the State of Delaware by the stockholder making the February 2021 Section 220 Demand to compel the production of books and records requested. After making an agreed books and records production, the Section 220 complaint was voluntarily dismissed effective September 21, 2021. The Company also provided substantially the same books and records production in response to the other three Section 220 requests described above. It is possible that one or more additional stockholder suits could be filed pertaining to the subject matter of the Section 220 Demands and the class and derivative actions described above.
Other Legal Matters
The Company is a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued when management determines they are probable based on its best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company’s financial position, results of operations or cash flows.
Contingency Reserves
When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters infor which reserves have been established. The Company believes that any such amount above the amounts accrued would not be material to the Condensed Consolidated Financial Statements. Future changes in facts and circumstances not currently known or foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

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9. Employee Benefit PlansRevenue Recognition
Postretirement BenefitsDisaggregation of Revenue
The changefollowing table presents revenues from contracts with customers disaggregated by product:
Three Months Ended March 31,
(In millions)20222021
Natural gas$1,111 $473 
Oil699 — 
NGL245 — 
Other15 — 
$2,070 $473 
All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer and generated in the Company's postretirement benefitUnited States of America.
Transaction Price Allocated to Remaining Performance Obligations
A significant number of the Company’s product sales contracts are short-term in nature, with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is as follows:part of a contract that has an original expected duration of one year or less.
(In thousands) Nine Months Ended September 30, 2017 Year Ended December 31, 2016
Change in Benefit Obligation    
Benefit obligation at beginning of the period $37,482
 $36,626
Service cost 1,163
 2,323
Interest cost 810
 1,498
Actuarial (gain) loss 3,084
 (2,846)
Benefits paid (817) (934)
Curtailment (gain) loss (4,185) —
Plan amendments (8,643) 815
Benefit obligation at end of the period 28,894
 37,482
Change in Plan Assets    
Fair value of plan assets at end of the period —
 —
Funded status at end of the period $(28,894) $(37,482)
In September 2017, in conjunction with its saleAs of properties located in West Virginia, Virginia and Ohio,March 31, 2022, the Company terminated approximately 100 employees. Ashad $7.6 billion of unsatisfied performance obligations related to natural gas sales that have a result,fixed pricing component and a contract term greater than one year. The Company expects to recognize these obligations over periods ranging from two to 16 years.
Contract Balances
Receivables from contracts with customers are recorded when the employees’ participation in the postretirement plan terminated,right to consideration becomes unconditional, which resulted in a remeasurement and curtailmentis generally when control of the postretirement benefit obligation at September 30, 2017.product has been transferred to the customer. Receivables from contracts with customers were $1,004 million and $922 million as of March 31, 2022 and December 31, 2021, respectively, and are reported in accounts receivable, net on the Condensed Consolidated Balance Sheet. As of March 31, 2022, the Company has no assets or liabilities related to its revenue contracts, including no upfront payments or rights to deficiency payments.
The change in benefit obligation for the nine months ended September 30, 2017 also reflects a plan amendment for the Company's change from a Medicare Supplemental program to a Medicare Advantage program for participants age 65 and older. This coverage continues to be provided under a fully-insured arrangement.
Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income (Loss)
  Nine Months Ended September 30,
(In thousands) 2017 2016
Components of Net Periodic Postretirement Benefit Cost    
Service cost $1,163
 $1,743
Interest cost 810
 1,123
Amortization of prior service cost (credit) (934) 83
Net periodic postretirement cost $1,039
 $2,949
Recognized curtailment (gain) loss (4,850) —
Total postretirement cost (benefit) $(3,811) $2,949
Other Changes in Benefit Obligations Recognized in Other Comprehensive Income (Loss)    
Net (gain) loss $2,266
 $—
Amortization of prior service cost 2,416
 (83)
Prior service credit (8,643) —
Total recognized in other comprehensive income $(3,961) $(83)
  
  
Total recognized in net periodic benefit cost and other comprehensive income (loss) $(7,772) $2,866

Assumptions
Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:
(In thousands) September 30,
2017		 December 31,
2016
Discount rate 4.00% 4.30%
Health care cost trend rate for medical benefits assumed for next year (pre-65) 7.75% 7.50%
Health care cost trend rate for medical benefits assumed for next year (post-65) 6.00% 5.00%
Ultimate trend rate (pre-65) 4.50% 4.50%
Ultimate trend rate (post-65) 4.50% 4.50%
Year that the rate reaches the ultimate trend rate (pre-65) 2030
 2023
Year that the rate reaches the ultimate trend rate (post-65) 2023
 2018
10. Capital Stock
TreasuryDividends
Common Stock
In August 1998,February 2022, the Company’s Board of Directors approved an increase in the quarterly base dividend on the Company's common stock from $0.125 per share to $0.15 per share. Also on that date, the Board of Directors approved a variable dividend of $0.41 per share, resulting in a base-plus-variable dividend of $0.56 per share on the Company’s common stock.
Subsequent Event. In May 2022, the Company’s Board of Directors approved the quarterly base dividend of $0.15 per share and a variable dividend of $0.45 per share, resulting in a base-plus-variable dividend of $0.60 per share on the Company’s common stock.
Treasury Stock
In February 2022, the Company’s Board of Directors terminated the previously authorized a share repurchase program under whichand authorized a new share repurchase program. This new share repurchase program authorizes the Company mayto purchase sharesup to $1.25 billion of the Company’s common stock in the open market or in negotiated transactions. The timing and amount of any stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs currently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase common stock of the Company.
During the first ninethree months of 2017,ended March 31, 2022, the Company repurchased 3.08 million shares for a total cost$192 million under the new share repurchase program, including repurchases of $68.3 million. Since the authorization date, the Company has repurchased 32.9$8 million shares of the 40.0 million total shares authorized for a total cost of approximately $456.6 million, of which 20.0 million shares have been retired. No treasury shares have been delivered or sold by the Company subsequentthat were purchased prior to the repurchase.March 31, 2022 and settled in April 2022. As of September 30, 2017, 12.9March 31, 2022, 87 million shares were held as treasury stock.stock, with $1.1 billion remaining under the Company’s current share repurchase program.
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11. Stock-basedStock-Based Compensation
General
From time to time theThe Company grants certain stock-based compensation awards, including restricted stock awards, restricted stock units, and performance share awards.awards and stock options. Stock-based compensation expense associated with these awards was $7.8$23 million and $5.1$12 million in the third quarterfirst quarters of 20172022 and 2016, respectively, and $26.2 million and $23.0 million during the first nine months of 2017 and 2016,2021, respectively. Stock-based compensation expense is included in general and administrative expense in the Condensed Consolidated Statement of Operations.
As described in Note 1 to the Condensed Consolidated Financial Statements, effective January 1, 2017, the Company adopted ASU No. 2016-09, which requires that excess tax benefits and tax deficiencies on stock-based compensation be recorded in the income statement. During the first nine months of 2017, the Company recorded an increase to tax expense of $2.6 million in the Condensed Consolidated Statement of Operations as a result of book compensation cost for employee stock-based compensation exceeding the federal and state tax deductions for awards that vested during the period.
Prior to the adoption of ASU No. 2016-09, windfall tax benefits were recorded in additional paid in capital in the Condensed Consolidated Balance Sheet and tax shortfalls reduced additional paid in capital to the extent they offset previously recorded windfall tax benefits. During the first nine months of 2016, the Company recorded a tax shortfall of $2.1 million, resulting in a reduction of the Company's windfall tax benefit that was recorded in additional paid in capital in the Condensed Consolidated Balance Sheet. The tax shortfall was a result of book compensation cost for employee stock-based compensation exceeding the federal and state tax deductions for certain awards that vested during the period.
Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of stock-based compensation awards and the applicable award terms.

Restricted Stock Units
During the first ninethree months of 2017, 57,0282022, the Company granted 1,222,705 restricted stock units were granted to non-employee directors of the Company with a weighted-averageweighted average grant date value of $22.94$23.33 per unit. The fair value of these unitsrestricted stock unit grants is measured based on the closing stock price on the grant date. Restricted stock units generally vest either at the end of a three-year service period or on a graded or graduated vesting basis at each anniversary date andover a three or four year service period. The Company used an annual forfeiture rate assumption of zero to 5 percent for purposes of recognizing stock-based compensation expense is recorded immediately. These units immediately vest and are issued when the director ceases to be a director of the Company.for its restricted stock units.
Performance Share Awards
The performance period for the awards granted by the Company during the first ninethree months of 20172022 commenced on JanuaryFebruary 1, 20172022 and ends on DecemberJanuary 31, 2019.2025. The Company used an annual forfeiture rate assumption ranging from 0% to 6%of zero percent for purposes of recognizing stock-based compensation expense for its performance share awards.
Performance Share Awards Based on Internal Performance Metrics
The fair value of performance share award grants based on internal performance metrics is based on the closing stock price on the grant date. Each performance share award represents the right to receive up to 100% of the award in shares of common stock. Based on the Company’s probability assessment at September 30, 2017, it is considered probable that the criteria for all performance awards based on internal metrics awards will be met.
Employee Performance Share Awards.During the first nine months of 2017, 406,460 Employee Performance Share Awards were granted at a grant date value of $22.60 per share. The performance metrics are set by the Company’s compensation committee and are based on the Company’s average production, average finding costs and average reserve replacement over a three-year performance period.
Hybrid Performance Share Awards.During the first nine months of 2017, 272,920 Hybrid Performance Share Awards were granted at a grant date value of $22.60 per share. The 2017 awards vest 25% on each of the first and second anniversary dates and 50% on the third anniversary, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date, as set by the Company’s compensation committee. If the Company does not meet the performance metric for the applicable period, then the portion of the performance shares that would have been issued on that anniversary date will be forfeited.
Performance Share Awards Based on Market Conditions
These awards have both an equity and liability component, with the right to receive up to the first 100%100 percent of the award in shares of common stock and the right to receive up to an additional 100%100 percent of the value of the award in excess of the equity component in cash. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model.
TSR Performance Share Awards. During the first nine months of 2017, 409,380 TSR Performance Share Awards were. During the first three months of 2022, the Company granted and1,161,599 performance share awards (the “TSR Performance Share Awards”) which are earned, or not earned, based on the comparative performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group and certain industry-related indices over a three-year performance period. The 2022 TSR Performance Share Awards include a feature that will reduce the potential cash component of the award if the actual performance is negative over the three-year period and the base calculation indicates an above-target payout.
The following assumptions were used to determine the grant date fair value of the equity component (February 22, 2017)on February 28, 2022 and the period-end fair value of the liability component of the TSR Performance Share Awards:
 Grant DateMarch 31,
2022
Fair value per performance share award$17.89 $14.81 
Assumptions:  
     Stock price volatility42.3 %43.7 %
     Risk-free rate of return1.60 %2.41 %
  Grant Date September 30, 2017
Fair value per performance share award $19.85
 $12.28-$20.22
Assumptions:  
  
     Stock price volatility 37.8% 20.8% - 39.9%
     Risk free rate of return 1.4% 1.1% - 1.5%
12. Earnings per Common Share
Basic earnings per share (EPS)(“EPS”) is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly calculated, except that the common shares outstanding for the period is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock appreciation rights were exercised and stock awards were vested at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

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The following is a calculation of basic and diluted weighted-average shares outstanding:earnings per share:
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
(In thousands) 2017 2016 2017 2016
Weighted-average shares - basic 462,498
 465,149
 464,194
 454,060
Dilution effect of stock appreciation rights and stock awards at end of period 2,282
 —
 1,816
 —
Weighted-average shares - diluted 464,780
 465,149
 466,010
 454,060
Three Months Ended 
March 31,
(In millions except per share amounts)20222021
Income (Numerator)
Net income$608 $126 
Less: dividends attributable to participating securities(2)— 
Less: Cimarex redeemable preferred stock dividends(1)— 
Net income available to common stockholders$605 $126 
Shares (Denominator)
Weighted-average shares - Basic810 399 
Dilution effect of stock awards at end of period4 3 
Weighted-average shares - Diluted814 402 
Earnings per share:
Basic$0.75 $0.32 
Diluted$0.74 $0.31 
The following is a calculation of weighted-average shares excluded from diluted EPS due to the anti-dilutive effect:
Three Months Ended 
March 31,
(In millions)20222021
Weighted-average stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method1 1 
13. Related Party Transactions
From time to time, Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to the Company. The Company incurred drilling costs of approximately $3 million related to these services during the three months ended March 31, 2022.
Hans Helmerich, a director of the Company, is the Chairman of the Board of Directors of H&P.
14. Restructuring Costs
In connection with the Merger, the Company incurred certain merger-related restructuring costs that are primarily related to workforce reductions and the associated employee severance benefits that were triggered by the Merger. The Company recognized $24 million of restructuring expenses during 2022 related to the accrual of employee-related severance and termination benefits associated with the expected termination of certain Cimarex employees.
The following table summarizes the Company’s restructuring liabilities:
(In millions)Three Months Ended March 31, 2022
Balance at beginning of period$43 
Additions related to merger integration24 
Reductions related to merger integration payments(3)
Balance at end of period$64 
17
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
(In thousands) 2017 2016 2017 2016
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect due to net loss —
 1,784
 —
 1,326
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method 2
 —
 6
 1
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect 2
 1,784
 6
 1,327
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13.15. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
(In millions)March 31,
2022		December 31,
2021
Accounts receivable, net  
Trade accounts$1,004 $922 
Joint interest accounts70 83 
Other accounts22 34 
 1,096 1,039 
Allowance for doubtful accounts(2)(2)
 $1,094 $1,037 
Other assets  
Deferred compensation plan$46 $47 
Debt issuance costs4 5 
Operating lease right-of-use assets308 317 
Other accounts26 20 
 $384 $389 
Accounts payable
Trade accounts$41 $94 
Royalty and other owners393 315 
Accrued transportation90 96 
Accrued capital costs149 88 
Taxes other than income77 60 
Accrued lease operating costs29 29 
Other accounts95 65 
 $874 $747 
Accrued liabilities
Employee benefits$92 $124 
Taxes other than income13 13 
Operating lease liabilities71 69 
Financing lease liabilities6 14 
Other accounts27 40 
 $209 $260 
Other liabilities
Deferred compensation plan$60 $56 
Postretirement benefits28 33 
Operating lease liabilities237 248 
Financing lease liabilities15 7 
Other accounts70 63 
 $410 $407 
18
(In thousands) September 30,
2017		 December 31,
2016
Accounts receivable, net  
  
Trade accounts $162,069
 $185,594
Joint interest accounts 1,208
 1,359
Other accounts 425
 5,335
  163,702
 192,288
Allowance for doubtful accounts (2,012) (1,243)
  $161,690
 $191,045
     
Inventories  
  
Tubular goods and well equipment $12,130
 $11,005
Natural gas in storage 867
 2,299
  $12,997
 $13,304
     
Other current assets  
  
Prepaid balances and other $3,587
 $2,692
Derivative instruments 2,536
 —
  $6,123
 $2,692
     
Other assets  
  
Deferred compensation plan $14,336
 $12,587
Debt issuance costs 8,845
 11,403
Derivative instruments 3,763
 2,991
Other accounts 101
 58
  $27,045
 $27,039
     
Accounts payable  
  
Trade accounts $25,851
 $27,355
Natural gas purchases 3,457
 2,231
Royalty and other owners 33,135
 36,472
Accrued transportation 48,104
 48,977
Accrued capital costs 33,440
 34,647
Taxes other than income 12,938
 13,827
Other accounts 3,864
 4,902
  $160,789
 $168,411
     
Accrued liabilities  
  
Employee benefits $17,065
 $14,153
Taxes other than income 4,018
 3,829
Asset retirement obligations 6,073
 2,000
Other accounts 158
 1,510
  $27,314
 $21,492
     
Other liabilities  
  
Deferred compensation plan $27,598
 $24,169
Other accounts 8,810
 4,952
  $36,408
 $29,121

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following review of operations of Coterra Energy Inc. (“Coterra,” “our,” “we” and “us”) for the three and nine month periods ended September 30, 2017March 31, 2022 and 20162021 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Quarterly Report on Form 10-Q (this “Form 10-Q”) and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Corporationour Annual Report on Form 10-K for the year ended December 31, 2016 (Form 10-K)2021 (our “Form 10-K”).
OVERVIEW
Cimarex Merger
On October 1, 2021, we completed a merger transaction (the “Merger”) with Cimarex Energy Co. (“Cimarex”). Cimarex is an oil and gas exploration and production company with operations in Texas, New Mexico and Oklahoma.
Certain financial and operational information set forth herein does not include the activity of Cimarex for periods prior to the closing of the Merger.
Financial and Operating Overview
Financial and operating results for the ninethree months ended September 30, 2017March 31, 2022 compared to the ninethree months ended September 30, 2016 are as follows:March 31, 2021 reflect the following:
•Equivalent production increased 49.7 Bcfe,22.7 MMBOE from 34.0 MMBOE, or 11%, from 463.0 Bcfe,381.1 MBOEPD, in 2021 to 56.7 MMBOE, or 1,689.6 Mmcfe per day,629.9 MBOEPD in 2016 to 512.7 Bcfe, or 1,877.9 Mmcfe per day, in 2017.2022.
•Natural gas production increased 49.450.6 Bcf from 205.8 Bcf, or 11%,2,287 Mmcf per day, in the 2021 period to 256.4 Bcf, or 2,850 Mmcf per day, in the 2022 period. The increase was attributable to production during the first quarter of 2022 from 441.8 Bcfproperties acquired in 2016the Merger, which significantly expanded our operations, partially offset by lower production related to 491.2 Bcf in 2017, as a resultthe timing of our drilling and completion activities in Pennsylvania.the Marcellus Shale in 2022.
Crude oil/condensate/•Oil production increased 8 Mmbbl from prior year. The increase was attributable to production from properties acquired in the Merger.
•NGL production increased 0.1 Mmbbls, or 2%,7 Mmbbl from 3.5 Mmbblsprior year. The increase was attributable to production from properties acquired in 2016 to 3.6 Mmbbls in 2017, as result of an increase in drilling and completion activity in south Texas partially offset by a natural decline in production.the Merger.
•Average realized natural gas price was $2.35$4.17 per Mcf, 45%$1.86 higher than the $1.62$2.31 per Mcf realized in the comparablecorresponding period of the prior year.
•Average realized crude oil price was $45.70and NGL prices for the first quarter of 2022 were $76.15 and $37.87 per Bbl, 27% higher than the $35.85 per Bbl realizedrespectively.
•Total capital expenditures were $326 million compared to $124 million in the comparablecorresponding period of the prior year.
Total The increase in capital expenditures were $582.8 million comparedwas attributable to $262.1 million inour expanded operations after the comparable period of the prior year.Merger.
•Drilled 7154 gross wells (62.5(41.4 net) with a success rate of 98.6%100 percent compared to 28 gross wells (28.0(25.1 net) with a success rate of 100%100 percent for the comparablecorresponding period of the prior year. Wells drilled represents wells drilled to total depth during the period.
•Completed 8138 gross wells (70.2(20.9 net) in 20172022 compared to 5114 gross wells (51.0(13.0 net) in 2016.the corresponding period of 2021. Wells completed includes wells completed during the period, regardless of when they were drilled.
•Average rig count during 20172022 was approximately 6.0, 2.6 and 2.0 rigs in the Permian Basin, Marcellus Shale approximately 1.0 rig in the Eagle Ford Shale and approximately 0.2 rigs in other areas,Anadarko Basin, respectively, compared to an average rig count of approximately 3.0 rigs in the Marcellus Shale during the corresponding period of approximately 1.1 rigs and approximately 0.3 rigs in the Eagle Ford Shale in 2016.
Received proceeds of $32.7 million primarily related2021 prior to the divestiture of certain oil and gas properties and related pipeline assets in West Virginia, Virginia and Ohio.Merger.
Repurchased 3.0 million shares of
•Paid dividends on our common stock of $0.56 per share, including $0.15 per share for regular quarterly dividend and $0.41 per share for a total costvariable dividend in February 2022.

Impact of $68.3 million.the COVID-19 Pandemic
The ongoing coronavirus (“COVID-19”) outbreak has caused widespread illness and significant loss of life, leading governments across the world to impose severely stringent limitations on movement and human interaction. Since the outbreak
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of the COVID-19 pandemic, we have implemented safety and preventative measures and developed response plans intended to minimize unnecessary risk of exposure and prevent infection among our employees and the communities in which we operate. We intend to continue to monitor developments affecting our workforce, our customers, our suppliers, our service providers and the communities in which we operate, including any significant resurgence in COVID-19 transmission and infection, and we will take such precautions as we believe are warranted should the need arise. Our efforts to respond to the challenges presented by the ongoing pandemic, as well as certain operational decisions we previously implemented, such as our maintenance capital program, have helped to minimize the impact, and any resulting disruptions, of the pandemic to our business and operations.
The long-term impact that the COVID-19 pandemic will have on our business, cash flows, liquidity, financial condition and results of operations will depend on future developments, including, among others, the duration, ultimate geographic spread and severity of the virus and its variants, the global availability and efficacy of treatments and vaccines and boosters and the acceptance of such treatments and vaccines by a significant portion of the population, any significant resurgence in virus transmission and infection in regions that have experienced improvements, the extent and duration of governmental and other measures implemented to try to slow the spread of the virus (whether through a continuation of existing measures or the re-imposition of prior measures), and other actions by governmental authorities, customers, suppliers and other third parties.
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of natural gas and crude oilcommodity prices and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions and other factors. In addition, ourOur realized prices are also further impacted by our hedging activities. Location differentials
In recent months, the conflict between Russia and Ukraine has driven oil and natural gas prices up significantly, in part because of sanctions by the European Union, the United Kingdom and the U.S. on imports of oil and gas from Russia, and is expected to have improvedfurther global economic consequences, including disruptions of the global supply chain and energy markets. Recent Russian actions have further contributed to global uncertainties for the future, causing even higher oil and natural gas prices. The ultimate impact of the war in certain regions,Ukraine will depend on future developments and the timing and extent to which normal economic and operating conditions resume.
However, continuing political and social attention to the issue of global climate change has resulted in both existing and pending national, regional, and local legislation and regulatory measures to limit or reduce emissions of greenhouse gases, such as mandates for renewable energy.
The trend in the Appalachian region, resulting in further increases inoil and natural gas regulation has been to increase regulatory restrictions and limitations on such activities. Any changes in, or more stringent enforcement of, these laws and regulations may result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements which could have an adverse effect on our financial results.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices, particularly oil and natural gas prices. Material declines in commodity prices could have a material adverse effect on our operating results, financial condition, liquidity and ability to obtain financing. Lower commodity prices also may reduce the amount of oil, natural gas, and NGLs that we can produce economically. In addition, in periods of low commodity prices, we may elect to curtail a portion of our production from time to time. Historically, commodity prices have been volatile, with prices sometimes fluctuating widely, and they may remain volatile. As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. We expect natural gas and crude oil prices to remain volatile. In addition to commodity prices and production volumes, and commodity prices, finding and developing sufficient amounts of oil and natural gas and crude oil reserves at economical costs are critical to our long-term success. For information aboutCertain of our capital expenditures and expenses are affected by general inflation and we expect costs for the impactremainder of realized commodity prices on our natural gas and crude oil and condensate revenues, refer2022 to “Results of Operations” below.continue to increase.
We account for our derivative instruments on a mark-to-market basis, with changes in fair value recognized in operating revenues in the Condensed Consolidated Statement of Operations. As a result of these mark-to-market adjustments associated with our derivative instruments, we will

likely experience volatility in our earnings due to commodity price volatility. Refer to “Impact“Results of Derivative Instruments on Operating Revenues”Operations” below and Note 5 of the Notes to the Condensed Consolidated Financial Statements for more information.
CommodityNYMEX oil and natural gas futures prices have remained volatile butstrengthened since the reduction of pandemic-related restrictions and recent OPEC+ cooperation. Improving oil and natural gas futures prices in part reflect market expectations of limited U.S. supply growth from publicly traded companies as a result of capital investment discipline and a focus on delivering free cash
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flow returns to stockholders. In addition, natural gas prices have benefited from strong worldwide liquefied natural gas (“LNG”) demand, including as a result of buyers shifting from Russian gas due to the Ukraine invasion, and sustained higher U.S. exports, lower associated gas growth from oil drilling and improved U.S. economic activity. Oil price futures have improved during 2017 comparedcoinciding with recovering global economic activity, lower supply from major oil producing countries, OPEC+ cooperation and moderating inventory levels.
Although the current outlook on oil and natural gas prices is generally favorable and our operations have not been significantly impacted in the short-term, in the event further disruptions occur and continue for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may increase. Although we are unable to predict future commodity prices, at current oil, natural gas and NGL price levels, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the fourth quarter of 2016. Innear future; however, in the event that commodity prices significantly decline from current levels, our management would testevaluate the recoverability of the carrying value of itsour oil and gas properties and, if necessary, record an impairment charge.properties.
We believe that we are well-positioned to manageFor information about the challenges presented in a depressed commodity pricing environment, and that we can endure the continued volatility in current and futureimpact of realized commodity prices by:on our revenues, refer to “Results of Operations” below.
Continuing to exercise discipline in ourOutlook
Our 2022 capital program with the expectation of funding ouris expected to be approximately $1.4 billion to $1.5 billion, which includes $1.2 billion to $1.3 billion for drilling and completion activities. We expect to fund these capital expenditures with cash on hand, operating cash flows, and if required, borrowings under our revolving credit facility.
Continuing to optimize our drilling, completion and operational efficiencies, resulting in lower operating costs per unit of production.
Continuing to manage our balance sheet, which provides sufficient availability under our revolving credit facility and existing cash balances to meet our capital requirements and maintain compliance with our debt covenants.
Continuing to manage price risk by strategically hedging our natural gas and crude oil production.
Outlook
Based on the expectation for higher operating cash flow due to an improvement in the commodity price outlook, we increased our 2017 budgeted capital expenditures compared to 2016. Our full year 2017 capital spending program includes approximately $775.0 million in capital expenditures related to our drilling and completion program, leasehold acquisitions and contributions of approximately $70.0 million to our equity method investments. All such expenditures are expected to be funded by existing cash, operating cash flow and, if required, borrowings under our revolving credit facility.cash on hand.
In 2016,2021, we drilled 40114 gross wells (38.0(99.9 net) and completed 76132 gross wells (76.0(108.3 net), of which 6214 gross wells (62.0(13.0 net) were drilled but uncompleted in prior years. In 2017,For the first three months of 2022, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 41.4 net wells and completed 20.9 net wells. Our capital program for the remainder of 2022 will focus on execution of our 2022 plan, to drill 100 gross wells (95.0 net)which remains in line with the full-year guidance released in February. We allocate our planned program for capital expenditures based on market conditions, return on capital and complete 95 gross wells (90.0 net),free cash flow expectations and availability of which 51 gross wells (45.0 net) were drilled but uncompleted in prior years. In 2017, we plan to operate an average of approximately 3.0 rigs, an increase from an average of approximately 1.4 rigs in 2016.services and human resources. We will continue to assess the oil and natural gas and crude oil price environment along with our liquidity position and may increase or decreaseadjust our capital expenditures accordingly.
Financial ConditionFINANCIAL CONDITION
Liquidity and Capital Resources
We strive to maintain an adequate liquidity level to address commodity price volatility and Liquidity
risk. Our primary sources of liquidity are (1) cash for the nine months ended September 30, 2017 were from the saleon hand, (2) net cash provided by operating activities and (3) available borrowing capacity under our revolving credit facility.
Our liquidity requirements consist primarily of natural gas and crude oil production and proceeds from the sale of assets. These cash flows were primarily used to fund our(1) capital expenditures, (including contributions to our equity method investments),(2) payment of contractual obligations, including debt maturity and interest payments, on debt, repurchase of shares of our common stock(3) working capital requirements, (4) dividend payments and payment of dividends.(5) share repurchases. See below for additional discussion and analysis of our cash flow.
The borrowing base under the terms of our revolving credit facility is redetermined annually in April. In addition, either we or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. Effective April 11, 2017, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively. There were no borrowings outstanding under our revolving credit facility as of September 30, 2017.
We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt.flows. We believe that, with the existingoperating cash flow, cash on hand operating cash flow and availability under our revolving credit facility, we have the capacityability to fundfinance our spending plans.plans over the next twelve months and, based on current expectations, for the long term.
At September 30, 2017,March 31, 2022, we had no borrowings outstanding under our revolving credit facility and our unused commitments were $1.5 billion. We also have unrestricted cash on hand of $1.4 billion as of March 31, 2022.
Our revolving credit facility includes a covenant limiting our borrowing capacity based on our leverage ratio. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Debt and Credit Agreements,” in our Form 10-K for further details regarding our leverage ratio.
Our debt is currently rated as investment grade by the three leading rating agencies. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, current commodity prices, our liquidity position, our asset quality and reserve mix, debt levels, cost structure and growth plans. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. There are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities should our debt rating fall below a certain level. However, a change in our debt rating could impact our interest rate on any borrowings under our revolving credit facility and our ability to economically access debt markets in the future and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit facility.
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Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-strategic assets, and, from time to time, private or public financing based on our monitoring of capital markets and our balance sheet. We also may use a combination of these sources of funds to refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise, but we have no obligation to do so.
At March 31, 2022, we were in compliance with all restrictive financial and other covenants for both theapplicable to our revolving credit facility and senior notes. As of September 30, 2017, based on our asset coverage and leverage ratios, there were no interest rate adjustments required for our senior notes. SeeRefer to our Form 10-K for further discussion of our restrictive financial covenants.

Cash Flows
Our cash flows from operating activities, investing activities and financing activities arewere as follows:
Three Months Ended 
March 31,
(In millions)20222021
Cash flows provided by operating activities$1,322 $290 
Cash flows used in investing activities(269)(123)
Cash flows used in financing activities(642)(134)
Net increase in cash, cash equivalents and restricted cash$411 $33 
  Nine Months Ended 
 September 30,
(In thousands) 2017 2016
Cash flows provided by operating activities $719,047
 $257,705
Cash flows used in investing activities (577,484) (220,141)
Cash flows provided by (used in) financing activities (129,849) 463,115
Net increase in cash and cash equivalents $11,714
 $500,679
Operating Activities.Activities.Operating cash flow fluctuations are substantially driven by commodity prices, changes in ourcommodity prices, production volumes and operating expenses. Prices for natural gas and crude oilCommodity prices have historically been volatile, primarily as a result of supply and demand for oil and natural gas, and crude oil, pipeline infrastructure constraints, basis differentials, inventory storage levels, seasonal influences and seasonal influences.geopolitical, economic and other factors. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures. We
On October 1, 2021, we and Cimarex completed the Merger. Although we expect to achieve certain general and administrative expense synergies over the long-term through cost savings, in the near-term we will continue to incur certain Merger-related costs, which in total are unableexpected to predict future commodity pricesrange from $100 million to $110 million. These payments will primarily relate to workforce reductions and as a result, cannot provide any assurance about future levels of net cash provided by operating activities.the associated employee severance benefits.
Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit facility, repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, sales andpayment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time to time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. At September 30, 2017March 31, 2022 and December 31, 2016,2021, we had a working capital surplus of $279.8$938 million and $458.1$916 million, respectively. We believe we have adequate liquidity and availability under our revolving credit facility to meet our working capital requirements over the next 12 months.
Net cash provided by operating activities infor the first ninethree months of 2017ended March 31, 2022 increased by $461.3 million$1.0 billion compared to the first nine months of 2016.same period in 2021. This increase was primarily due to higher operating revenues,natural gas, oil and NGL revenue, partially offset by higher operating expenses, higher cash operating expenses.paid on derivative settlements and higher changes in working capital and other assets and liabilities. The increase in operating revenuesnatural gas, oil and NGL revenue was primarily due to our expanded operations after the Merger and an 81 percent increase in realized natural gas and crude oil prices and higher equivalent production. Average realized natural gas and crude oil prices increased by 45% and 27%, respectively, forfrom the first ninethree months of 2017 comparedended March 31, 2021 to the first ninethree months of 2016. Equivalent production increased by 11% for the first nine months of 2017 comparedended March 31, 2022.
Refer to the first nine months of 2016 driven by higher natural gas production in the Marcellus Shale.
See “Results of Operations” below for additional information relative to commodity price, production and operating expense fluctuations. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.
Investing Activities.Cash flows used in investing activities increased by $357.3$146 million for the first ninethree months of 20172022 compared to the first ninethree months of 2016.2021. The increase was primarily due to $341.8$148 million of higher capital expenditures and $16.4 million lower proceeds fromas a result of our expanded operations after the sale of assets, partially offset by $0.8 million lower capital contributions associated with our equity method investments.Merger.
Financing Activities.Cash flows provided byused in financing activities decreasedincreased by $593.0$508 million for the first ninethree months of 20172022 compared to the first ninethree months of 2016.2021. This decreaseincrease was primarily due to $995.3 million lower net proceeds from the issuance of common stock in 2016, $68.3 million of repurchases of our common stock in 2017 and $28.8 million of higher dividend payments related to anof $416.0 million as a result of the increase in theour base dividend rate from $0.10 per share in April 2021 to $0.15 per share in February 2022, the payment of a variable dividend of $0.41 per share in February 2022 and additional shares issued in October 2021 as consideration in the issuanceMerger. The increase in cash flows from financing activities was also due to share repurchases of common stock in 2016.
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$184 million during the first three months of 2022. These decreasesincreases were partially offset by $497.0 million of lower net repayments of debt due to the repayment of the outstanding balance on our revolving credit facility and certain of our senior notes with the proceeds from the issuance of common stock in 2016.

$88 million.
Capitalization
Information about our capitalization is as follows:
(In millions)March 31,
2022		December 31,
2021
Debt (1)
$3,115 $3,125 
Stockholders' equity11,718 11,738 
Total capitalization$14,833 $14,863 
Debt to total capitalization21 %21 %
Cash and cash equivalents$1,447 $1,036 

(1)Includes $25 million of current portion of long-term debt at March 31, 2022. There were no borrowings outstanding under our revolving credit facility as of March 31, 2022 and December 31, 2021.
(In thousands) September 30,
2017		 December 31,
2016
Debt (1)
 $1,521,551
 $1,520,530
Stockholders' equity 2,644,594
 2,567,667
Total capitalization $4,166,145
 $4,088,197
Debt to total capitalization 37% 37%
Cash and cash equivalents $510,256
 $498,542
(1)
Includes $237.0 million of current portion of long-term debt at September 30, 2017.
During the first nine months of 2017,Share repurchases. Under our authorized share repurchase program approved in February 2022, we repurchased 3.08 million shares of our common stock for $68.3 million.$192 million during the first three months of 2022. We alsodid not repurchase any shares of our common stock during the first three months of 2021.
Dividends. During the first three months of 2022, we paid dividends of $55.7$456 million, which included a quarterly dividend on our common stock of $0.15 per share and a variable dividend of $0.41 per share, and a dividend of $23.125 per share on Cimarex’s redeemable preferred stock. During the first three months of 2021, we paid dividends of $40 million ($0.120.10 per share) on our common stock.
In May 2017, the2022, our Board of Directors approved an increasea quarterly base dividend of $0.15 per share and a variable dividend of $0.45 per share, resulting in the quarterlya total base-plus-variable dividend of $0.60 per share on our common stock from $0.02 per share to $0.05 per share.stock.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash generated from operations, and, if required, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.
The following table presents major components of our capital and exploration expenditures:
Three Months Ended 
March 31,
(In millions)20222021
Capital expenditures:  
Drilling and facilities$314 $123 
Leasehold acquisitions1 1 
Pipeline and gathering8 — 
Other3 — 
 326 124 
Exploration expenditures(1)
6 3 
$332 $127 

  Nine Months Ended 
 September 30,
(In thousands) 2017 2016
Capital expenditures  
  
Drilling and facilities $475,240
 $255,139
Leasehold acquisitions 97,835
 1,687
Pipeline and gathering 597
 1,009
Other 9,091
 4,251
  582,763
 262,086
Exploration expenditures 16,623
 13,109
Total $599,386
 $275,195
(1)There were no exploratory dry hole costs for the first threemonths of 2022 and 2021.
For the full yearfirst three months of 2017,2022, our capital program was focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 41.4 net wells and completed 20.9 net wells. We expect our 2022 capital program to be approximately $1.4 billion to $1.5 billion and will focus on the Permian Basin, where we are currently running six rigs and two completion crews, and the Marcellus Shale, where we are currently running two rigs and plan to drill approximately 100 gross wells (95.0 net) and complete 95 gross wells (90.0 net), of which 51 gross wells (45.0 net) were drilled but uncompleted in prior years. In 2017, our drilling program includes approximately $775.0 million in total capital expenditures comparedrun one to $372.5 million in 2016. Seetwo completion crews. Refer to “Outlook” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oilcommodity price environment along with our liquidity position and may increase or decreaseadjust our capital expenditures accordingly. 
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Contractual Obligations
We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Transportation and Gathering Agreements,” “Drilling Rig Commitments,”Agreements” and “Lease Commitments” and “Hydraulic Fracturing Services Commitments” as disclosed in Note 9 in8 of the Notes to the Consolidated Financial Statements and the obligations described under “Contractual Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based uponon our Condensed Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the

reported amounts of assets, liabilities, revenues and expenses. SeeRefer to our Form 10-K for further discussion of our critical accounting policies.
Recently Adopted
RESULTS OF OPERATIONS
First Three Months of 2022 and Recently Issued Accounting Pronouncements2021 Compared
Refer to Note 1Operating Revenues
 Three Months Ended March 31,Variance
(In millions)20222021AmountPercent
Operating Revenues
Natural gas$1,111 $473 $638 135 %
Oil699 — 699 100 %
NGL245 — 245 100 %
Loss on derivative instruments(391)(13)(378)(2,908)%
Other15 — 15 100 %
 1,679 460 1,219 265 %
Production Revenues
Our production revenues are derived from the sale of our oil, natural gas and NGL production. Our 2022 production revenues were substantially higher due to the Condensed Consolidated Financial Statements, “Financial Statement Presentation,” for a discussion of new accounting pronouncementsMerger, which significantly expanded our operations to include the Permian and Anadarko Basins. Increases and decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive. Commodity prices are market driven and we expect that affect us.
Results of Operations
Third Quarters of 2017 and 2016 Compared
We reported net income in the third quarter of 2017 of $17.6 million, or $0.04 per share, comparedfuture prices will continue to a net loss of $10.3 million, or $0.02 per share, in the third quarter of 2016. The increase in net income was primarilyfluctuate due to higher operating revenues, partially offset by higher operating expenses, loss on salesupply and demand factors, the availability of assetstransportation, seasonality and income tax expense.
Revenue, Pricegeopolitical, economic and Volume Variances
Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.
  Three Months Ended September 30, Variance
Revenue Variances (In thousands) 2017 2016 Amount Percent
   Natural gas $323,319
 $260,200
 $63,119
 24 %
   Crude oil and condensate 56,913
 37,777
 19,136
 51 %
   Gain (loss) on derivative instruments (836) 6,904
 (7,740) (112)%
   Brokered natural gas 3,528
 3,641
 (113) (3)%
   Other 2,492
 1,907
 585
 31 %
  $385,416
 $310,429
 $74,987
 24 %
  Three Months Ended September 30, Variance 
Increase
(Decrease)
(In thousands)
  2017 2016 Amount Percent 
Price Variances  
  
  
  
  
Natural gas $2.01
 $1.80
 $0.21
 12% $32,879
Crude oil and condensate $44.88
 $40.13
 $4.75
 12% 6,013
Total  
  
  
  
 $38,892
Volume Variances  
  
  
  
  
Natural gas (Bcf) 161.2
 144.4
 16.8
 12% $30,240
Crude oil and condensate (Mbbl) 1,268
 941
 327
 35% 13,123
Total  
  
  
  
 $43,363
other factors.
Natural Gas Revenues
The increase in natural
 Three Months Ended March 31,VarianceIncrease
(Decrease)
(In millions)
 20222021AmountPercent
Price variance ($/Mcf)$4.33 $2.30 $2.03 89 %$522 
Volume variance (Bcf)256.4205.8 50.625 %116 
    $638 
Natural gas revenues of $63.1increased $638 million wasprimarily due to significantly higher natural gas prices and production. The increase in production was a resultprimarily related to properties acquired in the Merger, which significantly expanded our operations, partially offset by lower production related to the timing of an increase in our drilling and completion activities in Pennsylvania.the Marcellus Shale in the first three months of 2022.

Crude Oil and Condensate Revenues
Oil revenues increased $699 million due to our expanded operations after the Merger.
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NGL Revenues
NGL revenues increased $245 million due to our expanded operations after the Merger.
Loss on Derivative Instruments
Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The increase in crudefollowing table presents the components of “Loss on derivative instruments” for the periods indicated:
 Three Months Ended 
March 31,
(In millions)20222021
Cash received (paid) on settlement of derivative instruments
Gas Contracts$(42)$3 
Oil Contracts(129)— 
Non-cash loss on derivative instruments
Gas Contracts(182)(16)
Oil Contracts(38)— 
$(391)$(13)
Operating Costs and Expenses
Costs associated with producing oil and condensate revenuesnatural gas are substantial. Among other factors, some of $19.1 million was due to higher crude oilthese costs vary with commodity prices, some trend with the volume and production. The increase incommodity mix of production, wassome are a resultfunction of an increase in our drillingthe number of wells we own, some depend on the prices charged by service companies, and completion activities in south Texas.
Impactsome fluctuate based on a combination of Derivative Instruments on Operating Revenues
  Three Months Ended 
 September 30,
(In thousands) 2017 2016
Cash received (paid) on settlement of derivative instruments  
  
Gain (loss) on derivative instruments $3,906
 $(8,101)
Non-cash gain (loss) on derivative instruments  
  
Gain (loss) on derivative instruments (4,742) 15,005
  $(836) $6,904
Brokered Natural Gas
  Three Months Ended September 30, Variance 
Price and
Volume
Variances
(In thousands)
  2017 2016 Amount Percent 
Brokered Natural Gas Sales        
  
  
Sales price ($/Mcf) $2.61
 $2.85
 $(0.24) (8)% $(327)
Volume brokered (Mmcf) x1,354
 x1,279
 75
 6 % 214
Brokered natural gas (In thousands) $3,528
 $3,641
     $(113)
             
Brokered Natural Gas Purchases            
Purchase price ($/Mcf) $2.07
 $2.30
 $(0.23) (10)% $(315)
Volume brokered (Mmcf) x1,354
 x1,279
 75
 6 % 173
Brokered natural gas (In thousands) $2,797
 $2,939
  
  
 $(142)
             
Brokered natural gas margin (In thousands) $731
 $702
  
  
 $29


Operating and Other Expenses
  Three Months Ended September 30, Variance
(In thousands) 2017 2016 Amount Percent
Operating and Other Expenses  
  
  
  
   Direct operations $26,282
 $24,626
 $1,656
 7 %
   Transportation and gathering 117,891
 105,671
 12,220
 12 %
   Brokered natural gas 2,797
 2,939
 (142) (5)%
   Taxes other than income 9,194
 8,771
 423
 5 %
   Exploration 6,466
 2,988
 3,478
 116 %
   Depreciation, depletion and amortization 146,267
 139,490
 6,777
 5 %
   General and administrative 23,244
 19,374
 3,870
 20 %
  $332,141
 $303,859
 $28,282
 9 %
         
Earnings (loss) on equity method investments $(1,417) $(1,727) $310
 (18)%
Loss on sale of assets (11,872) (1,245) (10,627) 854 %
Interest expense, net 20,331
 21,483
 (1,152) (5)%
Other expense (income) (5,083) 402
 (5,485) (1,364)%
Income tax expense (benefit) 7,151
 (8,027) 15,178
 189 %
Totalthe foregoing. Our operating costs and expenses from operationsin 2022 were substantially increased by $28.3 million, or 9%, in the third quarter of 2017 compareddue to the same periodMerger, which significantly expanded our operations to include the Permian and Anadarko Basins. In addition, our costs for services, labor and supplies have recently increased due to increased demand for those items and supply chain disruptions related to the COVID-19 pandemic and inflation.
The following table reflects our operating costs and expenses for the years indicated and a discussion of 2016. The primary reasons for this fluctuation are as follows:the operating costs and expenses follows.
 Three Months Ended March 31,VariancePer BOE
(In millions, except per BOE)20222021AmountPercent20222021
Operating Expenses    
Direct operations$100 $17 $83 488 %$1.76 $0.50 
Transportation, processing and gathering233 137 96 70 %4.11 3.99 
Taxes other than income76 5 71 1,420 %1.34 0.15 
Exploration6 3 3 100 %0.11 0.09 
Depreciation, depletion and amortization360 94 266 283 %6.35 2.74 
General and administrative107 29 78 269 %1.89 0.84 
$882 $285 $597 209 %
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Direct Operations
Direct operations expense generally consists of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (lease operating expense). Direct operations expense also includes well workover activity necessary to maintain production from existing wells. Direct operations expense consisted of lease operating expense and workover expense as follows:
Three Months Ended March 31,Per BOE
(In millions, except per BOE)20222021Variance20222021
Direct Operating Expense
Lease operating expense$82 $15 $67 $1.44 $0.44 
Workover expense18 2 16 0.32 0.06 
$100 $17 $83 $1.76 $0.50 
Lease operating and workover expense increased $1.7 million largelyprimarily due to anour expanded operations after the Merger, along with a slight increase in operating costs primarily driven by higher production, partially offset by improved operational efficiencies.workover expense in the Marcellus Shale.
Transportation, Processing and Gathering
Transportation, processing and gathering costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression and processing costs. Gathering costs also include costs associated with operating our gas gathering infrastructure, including operating and maintenance expenses. Costs vary by operating area and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.
Transportation, processing and gathering increased $12.2$96 million primarily due to higher throughput asour expanded operations after the Merger, along with a resultslight increase in gathering charges in the Marcellus Shale.
Taxes Other Than Income
Taxes other than income consist of higher Marcellus Shale production.
Brokeredproduction (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas decreased $0.1 million. Seeprices and ad valorem taxes being based on the precedingvalue of properties. The following table titled “Brokered Natural Gas”presents taxes other than income for further analysis.the periods indicated:
Three Months Ended March 31,
(In millions)20222021Variance
Taxes Other than Income
Production$63 $— $63 
Drilling impact fees7 5 2 
Ad valorem6 — 6 
$76 $5 $71 
Taxes other than income as a percentage of production revenue3.7 %1.1 %

Taxes other than income increased $0.4 million primarily due to $0.9 million higher production$71 million. Production taxes resulting from higher crude oil prices and production in south Texas, partially offset by $0.6 million lower drilling impact fees as a resultrepresented the majority of lower rates. The remaining changes inour taxes other than income, were not individually significant.which increased primarily due to higher production related to properties acquired in the Merger and higher commodity prices. Drilling impact fees increased primarily due to higher natural gas prices.
Exploration increased $3.5 million primarily as a result
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Table of higher geophysical costs of $2.0 millionContents
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased $6.8 million, primarily due to higher amortization(“DD&A”) expense consisted of unprovedthe following for the periods indicated:
Three Months Ended March 31,Per BOE
(In millions, except per BOE)20222021Variance20222021
DD&A Expense
Depletion$339 $91 $248 $5.98 $2.68 
Depreciation19 2 17 0.33 0.03 
Accretion of ARO2 1 1 0.04 0.03 
$360 $94 $266 $6.35 4.16$2.74 

Depletion of our producing properties is computed on a field basis using the units-of-production method under the successful efforts method of $9.4 million, partially offset by lower DD&Aaccounting. The economic life of $1.4 millioneach producing property depends upon the estimated proved reserves for that property, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved developed and proved reserves used in the third quartercalculation. Higher prices generally have the effect of 2017.increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The increasecost of replacing production also impacts our depletion expense. In addition, changes in amortizationestimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved properties is primarily due to an increase in leasing activityproved and an increase in amortization rates. The decrease in DD&A was due to a decrease of $17.3 million due to a lower DD&A rate of $0.75 per Mcfe for the third quarter of 2017 compared to $0.85 per Mcfe for the third quarter of 2016 primarily due to positive reserve revisions and the impairmentimpairments of oil and gas properties will also impact depletion expense. Our depletion expense increased $248 million due to increased production and related pipelinea higher depletion rate of $5.98 per BOE for the three months ended March 31, 2022, both of which are attributable to a significant increase in the value of the oil and gas properties acquired on the closing date of the Merger, compared to $2.68 per BOE for the three months ended March 31, 2021.
Fixed assets consist primarily of gas gathering facilities, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years. Also included in West Virginia and Virginia in 2016, partially offset by an increaseour depreciation expense is the depreciation of $15.8 millionthe right-of-use asset associated with higher equivalent production primarilyour finance lease gathering system. The increase in Pennsylvania fordepreciation expense during the third quarter of 2017three months ended March 31, 2022 as compared to the third quarter of 2016.three months ended March 31, 2021 is primarily due to increased depreciation on our gathering and facilities acquired in the Merger.
General and Administrative
General and administrative increased $3.9 million due to $3.2 million(“G&A”) expense consists primarily of severance costs for employees terminated as a result of the sale of properties located in West Virginia, Virginiasalaries and Ohio and $2.7 million of higherrelated benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred. Our G&A expense associated with certainis reported net of our market-based performance awards, partially offsetamounts reimbursed to us by $2.0 million lower professional services. The remaining changes in other general and administrative expenses were not individually significant.

Earnings (Loss) on Equity Method Investments
The increase in loss on equity method investments is a resultworking interest owners of our proportionate share of net loss from our equity method investments in 2017 compared to 2016.
Loss on Sale of Assets
Loss on sale of assets increased $10.6 million due to the Company's sale of certain proved and unproved oil and gas properties we operate. The table below reflects our G&A expense for the periods indicated:
Three Months Ended March 31,
(In millions)20222021Variance
G&A Expense
General and administrative expense$53 $17 $36 
Stock-based compensation expense23 12 11 
Merger-related expense31 — 31 
$107 $29 $78 

General and related pipeline assets located in West Virginia, Virginia and Ohio in the third quarter of 2017.
Other Expense (Income)
Other incomeadministrative expense increased $5.5$78 million primarily due to the curtailment gainMerger, which significantly expanded our headcount and office-related expenses.
Periodic stock-based compensation expense will fluctuate based on postretirement benefits as a resultthe grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards. Stock-based compensation expense increased $11 million primarily due to the issuance of additional shares as consideration in the Merger and increased headcount.
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Merger-related expenses increased $31 million primarily due to $7 million of Merger integration costs and $24 million of employee-related     severance and termination benefits associated with the expected termination of approximately 100certain Cimarex employees, in West Virginia, Virginia and Ohio.which is being accrued over the expected transition period.
Interest Expense, net
Interest expense net decreased $1.2increased $9 million primarily due to $0.8the incremental interest expense, net of premium amortization associated with the debt assumed in the Merger of $2.2 billion. This increase was partially offset by lower interest expense due to the repayment of $88 million higher interest income.of our 5.58% weighted-average private placement senior notes, which matured in January 2021, and the repayment of $100 million of our 3.65% weighted-average private placement senior notes, which matured in September 2021.
Income Tax Expense (Benefit)
Three Months Ended March 31,
(In millions)20222021Variance
Income Tax Expense
Current tax expense$134 $25 $109 
Deferred tax expense36 12 24 
$170 $37 $133 
Combined federal and state effective income tax rate22 %22 %

Income tax expense increased $15.2 million primarily due to higher pretax income, partially offset by a lower effective tax rate. The effective tax rates for the third quarter of 2017 and 2016 were 28.9% and 43.9%, respectively. The decrease in the effective tax rate is primarily due to a decrease in the blended state statutory tax rate as a result of changes in our state apportionment factors in the states in which we operate, as well as non-recurring discrete items recorded during the third quarter of 2017 versus the third quarter of 2016.
First Nine Months of 2017 and 2016 Compared
We reported net income in the first nine months of 2017 of $144.8 million, or $0.31 per share, compared to a net loss of $124.4 million, or $0.27 per share, in the first nine months of 2016. The increase in net income was primarily due to higher operating revenues, partially offset by higher operating expenses, loss on sale of assets and income tax expense.
Revenue, Price and Volume Variances
Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.
  Nine Months Ended September 30, Variance
Revenue Variances (In thousands) 2017 2016 Amount Percent
   Natural gas $1,152,089
 $711,010
 $441,079
 62%
   Crude oil and condensate 144,528
 114,610
 29,918
 26%
   Gain (loss) on derivative instruments 46,353
 (1,286) 47,639
 3,704%
   Brokered natural gas 12,260
 9,417
 2,843
 30%
   Other 8,486
 5,435
 3,051
 56%
  $1,363,716
 $839,186
 $524,530
 63%
  Nine Months Ended September 30, Variance 
Increase
(Decrease)
(In thousands)
  2017 2016 Amount Percent 
Price Variances  
  
  
  
  
Natural gas $2.35
 $1.61
 $0.74
 46% $361,545
Crude oil and condensate $45.13
 $35.92
 $9.21
 26% 29,451
Total  
  
  
  
 $390,996
Volume Variances  
  
  
  
  
Natural gas (Bcf) 491.2
 441.8
 49.4
 11% $79,534
Crude oil and condensate (Mbbl) 3,203
 3,190
 13
 —% 467
Total  
  
  
  
 $80,001

Natural Gas Revenues
The increase in natural gas revenues of $441.1 million was due to higher natural gas prices and production. The increase in production was a result of an increase in our drilling and completion activities in Pennsylvania.
Crude Oil and Condensate Revenues
The increase in crude oil and condensate revenues of $29.9 million was primarily due to higher crude oil prices.
Impact of Derivative Instruments on Operating Revenues
  Nine Months Ended 
 September 30,
(In thousands) 2017 2016
Cash received (paid) on settlement of derivative instruments  
  
Gain on derivative instruments $3,587
 $3,204
Non-cash gain (loss) on derivative instruments    
Gain (loss) on derivative instruments 42,766
 (4,490)
  $46,353
 $(1,286)
Brokered Natural Gas
  Nine Months Ended September 30, Variance 
Price and
Volume
Variances
(In thousands)
  2017 2016 Amount Percent 
Brokered Natural Gas Sales        
  
  
Sales price ($/Mcf) $3.17
 $2.38
 $0.79
 33 % $3,038
Volume brokered (Mmcf) x3,872
 x3,954
 (82) (2)% (195)
Brokered natural gas (In thousands) $12,260
 $9,417
     $2,843
             
Brokered Natural Gas Purchases            
Purchase price ($/Mcf) $2.65
 $1.90
 $0.75
 39 % $2,892
Volume brokered (Mmcf) x3,872
 x3,954
 (82) (2)% (156)
Brokered natural gas (In thousands) $10,262
 $7,526
  
  
 $2,736
             
Brokered natural gas margin (In thousands) $1,998
 $1,891
  
  
 $107

Operating and Other Expenses
  Nine Months Ended September 30, Variance
(In thousands) 2017 2016 Amount Percent
Operating and Other Expenses  
  
  
  
   Direct operations $78,185
 $77,139
 $1,046
 1 %
   Transportation and gathering 361,909
 322,883
 39,026
 12 %
   Brokered natural gas 10,262
 7,526
 2,736
 36 %
   Taxes other than income 26,562
 23,737
 2,825
 12 %
   Exploration 16,623
 13,109
 3,514
 27 %
   Depreciation, depletion and amortization 425,689
 448,910
 (23,221) (5)%
 Impairment of oil and gas properties 68,555
 —
 68,555
 100 %
   General and administrative 70,902
 67,192
 3,710
 6 %
  $1,058,687
 $960,496
 $98,191
 10 %
         
Earnings (loss) on equity method investments $(3,986) $208
 $(4,194) 2,016 %
Loss on sale of assets (13,498) (768) (12,730) 1,658 %
Interest expense, net 61,720
 67,821
 (6,101) (9)%
Loss on debt extinguishment —
 4,709
 (4,709) (100)%
Other expense (income) (4,974) 1,207
 (6,181) (512)%
Income tax expense (benefit) 85,965
 (71,243) 157,208
 221 %
Total costs and expenses from operations increased by $98.2 million, or 10%, in the first nine months of 2017 compared to the same period of 2016. The primary reasons for this fluctuation are as follows:
Direct operations increased $1.0 million largely due to an increase in operating costs primarily driven by higher production, partially offset by improved operational efficiencies, cost reductions from service providers and suppliers in 2017 compared to 2016.
Transportation and gathering increased $39.0$133 million due to higher throughput as a result ofpre-tax income attributable to higher Marcellus Shale production.
Brokered natural gas increased $2.7 million. See the preceding table titled “Brokered Natural Gas” for further analysis.
Taxes other than income increased $2.8 million due to $3.4 million higher production taxes primarily resulting from higher natural gas and crude oilcommodity prices and an increase in drilling impact fees of $1.9 million due to an increase in drilling activity in Pennsylvania. These increases were offset by a decrease of $2.4 million in ad valorem taxes as a result of lower property values primarily in south Texas.our expanded operations following the Merger.
Exploration increased $3.5 million as a result of higher dry hole costs of $2.8 million in 2017 and $2.6 million higher geophysical costs, partially offset by lower charges related to the release of certain drilling rig contracts in south Texas. In the first nine months of 2016, we recorded rig termination charges of $1.7 million. We recorded no rig termination charges in the first nine months of 2017.
Depreciation, depletion and amortization decreased $23.2 million, primarily due to lower DD&A of $38.0 million, partially offset by higher amortization of unproved properties of $15.9 million in 2017. The decrease in DD&A was due to a decrease of $82.5 million due to a lower DD&A rate of $0.73 per Mcfe for the first nine months of 2017 compared to $0.89 per Mcfe for the first nine months of 2016, partially offset by a $44.5 million increase due to higher equivalent production volumes. The lower DD&A rate was primarily due to positive reserve revisions and the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia in 2016. The increase in amortization of unproved properties is primarily due to the ongoing evaluation of our unproved properties and an increase in leasing activity.

Impairment of oil and gas properties was $68.6 million in 2017 due to the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia.
General and administrative increased $3.7 million due to $3.4 million higher employee-related expenses, $3.2 million of higher stock-based compensation expense associated with certain of our market-based performance awards and $3.2 million of severance costs for employees terminated as a result of its sale of properties located in West Virginia, Virginia and Ohio. These increases were partially offset by $6.8 million lower professional services. The remaining changes in other general and administrative expenses were not individually significant.
Earnings (Loss) on Equity Method Investments
The increase in loss on equity method investments is the result of our proportionate share of net earnings from our equity method investments in 2017 compared to 2016.
Loss on Sale of Assets
Loss on sale of assets increased $12.7 million due to the Company's sale of certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio in the third quarter of 2017.
Other Expense (Income)
Other income increased $6.2 million primarily due to the curtailment gain on postretirement benefits as a result of the termination of approximately 100 employees in West Virginia, Virginia and Ohio.
Interest Expense, net
Interest expense, net decreased $6.1 million primarily due to a $1.4 million increase in interest income and a $2.1 million decrease resulting from the repayment of the outstanding borrowings under our revolving credit facility in March 2016, which has remained undrawn through September 30, 2017. Interest expense also decreased $2.4 million resulting from the repurchase of $64.0 million of our 6.51% weighted-average senior notes in May 2016 and the repayment of $20.0 million of our 7.33% weighted-average senior notes in July 2016.
Loss on Debt Extinguishment
A $4.7 million debt extinguishment loss was recognized in the second quarter of 2016 related to the premium paid for the repurchase of a portion of our 6.51% weighted-average senior notes in May 2016 and the write-off of a portion of the associated deferred financing costs due to early repayment.
Income Tax Expense (Benefit)
Income tax expense increased $157.2 million due to higher pretax income and a higher effective tax rate. The effective tax rates for the first nine months of 2017 and 2016 were 37.2% and 36.4%, respectively. The increase in the effective tax rate is primarily due to an increase in the blended state statutory tax rate as a result of changes in our state apportionment factors in the states in which we operate and the impact of excess tax benefits and tax deficiencies on shares vesting during the period as a result of the adoption of ASU No. 2016-09 in January 2017, partially offset by non-recurring discrete items recorded during the first nine months of 2017 versus the first nine months of 2016.
Forward-Looking Information
The statements regarding future financial and operating performance and results, the anticipated effects of, and certain other matters related to, the Merger involving Cimarex, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “may,” “should,” “could,”“expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, ‘budget”, “plan”, “forecast”, “target”, “predict”, “potential”, “possible”, “may”, “should”, “could”, “would”, “will”, strategy”, “outlook” and similar expressions are also intended to identify forward-looking statements. SuchWe can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. Forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties including, butthat could cause actual results to differ materially from those included in this report. These risks and uncertainties include, without limitation, the continuing effects of the COVID-19 pandemic and the impact thereof on our business, financial condition and results of operations and the economy as a whole, the risk that our and Cimarex’s businesses will not limitedbe 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 availability of cash on hand and other sources of liquidity to fund our capital expenditures, actions by, or disputes among or between, members of OPEC+, market factors, market prices (including geographic basis differentials) of oil and natural gas, impacts of inflation, labor shortages and crude oil,economic disruption, including as a result of pandemics and geopolitical disruptions such as the war in Ukraine, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (“SEC”) filings. SeeRefer to “Risk Factors” in Item 1A of thePart I of our Form 10-K and in Item 1A of Part II of this Form 10-Q for additional information about these risks and uncertainties. Should oneForward-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, we undertake no obligation to update or morerevise any forward-looking statement, whether as a result of new information, future events or otherwise. You are cautioned not to place undue reliance on these risks or uncertainties materialize, orforward-looking statements, which speak only as of the date hereof.
Investors should underlying assumptions prove incorrect, actual outcomesnote that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may vary materially from those indicated.use the Investors section of our website (www.coterra.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of, and is not incorporated into, this report.

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ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
MarketIn the normal course of business, we are subject to a variety of risks, including market risks associated with changes in commodity prices and interest rate movements on outstanding debt. The following quantitative and qualitative information is provided about financial instruments to which we were party to as of March 31, 2022 and from which we may incur future gains or losses from changes in commodity prices or interest rates.
Commodity Price Risk
Our primarymost significant market risk exposure is exposurepricing applicable to our oil, natural gas and crude oil prices.NGL production. Realized prices are mainly driven by the worldwide pricesprice for crude oil and spot market prices for North American natural gas and NGL production. CommodityThese prices can behave been volatile and unpredictable. To mitigate the volatility in commodity prices, we may enter into derivative instruments to hedge a portion of our production.
Derivative Instruments and Risk Management Activities
Our risk management strategy is designed to reduce the risk of commodity price volatility for our production in the oil and natural gas and crude oil markets through the use of financial commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our financial commodity derivatives generally cover a portion of our production and, provide only partial price protection by limiting the benefit to us of increases in prices, while protecting us in the event of price declines.declines, limit the benefit to us in the event of price increases. Further, if any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our financial commodity derivatives. Please read the discussion below as well as Note 65 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivative and risk management activities.derivatives.
Periodically, we enter into financial commodity derivatives, including collar, swap, roll differential swap and basis swap agreements, to protect against exposure to commodity price declines related to our oil and natural gas and crude oil production. Our credit agreement restricts our ability to enter into financial commodity derivatives other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and that do not subjectingsubject us to material speculative risks. All of our financial derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.index.
As of September 30, 2017,March 31, 2022, we had the following outstanding financial commodity derivatives:
CollarsEstimated Fair Value Asset (Liability)
(In millions)
   FloorCeiling
Type of ContractVolume (Mmbtu)Contract PeriodRange
($/Mmbtu)		Weighted-Average
($/Mmbtu)
Range
($/Mmbtu)		Weighted-Average
($/Mmbtu)
Natural gas (NYMEX)74,900,000Apr. 2022 - Oct. 2022$3.00 - $4.50$3.61 $4.07 - $6.68$5.12 $(74)
Natural gas (Perm EP)(1)
1,820,000Apr. 2022 - Jun. 2022$— $2.40 $2.85 - $2.90$2.88 (3)
Natural gas (Perm EP)(1)
5,500,000Apr. 2022 - Dec. 2022$— $2.50 $— $3.15 (10)
Natural gas (PEPL)(2)
1,820,000Apr. 2022 - Jun. 2022$— $2.40 $2.81 - $2.91$2.86 (4)
Natural gas (PEPL)(2)
5,500,000Apr. 2022 - Dec. 2022$— $2.60 $— $3.27 (11)
Natural gas (Waha)(3)
1,820,000Apr. 2022 - Jun. 2022$— $2.40 $2.82 - $2.89$2.86 (3)
Natural gas (Waha)(3)
1,830,000Apr. 2022 - Sep. 2022$— $2.40 $— $2.77 (4)
Natural gas (Waha)(3)
5,500,000Apr. 2022 - Dec. 2022$— $2.50 $— $3.12 (9)
Natural gas (NYMEX)71,500,000Apr. 2022 - Dec 2022$3.50 - $4.25$3.84 $4.75 - $6.60$5.39 (59)
Natural gas (NYMEX)52,850,000Nov 2022 - Mar 2023$4.00 - $4.75$4.46 $7.00 - $10.10$8.37 (15)
$(192)

(1)The index price is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.
(2)The index price is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.
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       Collars   Basis Swaps 
Estimated 
Fair Value 
Asset (Liability)
(In thousands)
       Floor Ceiling Swaps  
Type of Contract Volume Contract Period Range 
Weighted-
Average
 Range 
Weighted-
Average
 
Weighted-
Average
 Weighted- Average 
Natural gas - NYMEX 8.9
Bcf Oct. 2017 - Dec. 2017         $3.12
   $(177)
Natural gas - TCO 4.5
Bcf Oct. 2017 - Dec. 2017         $3.46
   2,322
Natural gas - NYMEX 8.9
Bcf Oct. 2017 - Dec. 2017 $—
 $3.09
 $3.42-$3.45 $3.43
     261
Natural gas - Transco 21.3
Bcf Jan. 2018 - Dec. 2019           $0.42
 2,858
Crude oil 0.5
Mmbbl Oct. 2017 - Dec. 2017 $—
 $50.00
 $56.25-$56.50 $56.39
     259
                   $5,523
(3)The index price is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.
In the above table, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.
CollarsSwapsEstimated Fair Value Asset (Liability)
(In millions)
FloorCeilingBasis SwapsRoll Swaps
Type of 
Contract		Volume (Mbbl)Contract PeriodRange
 ($/Bbl)		Weighted-Average ($/Bbl)Range
($/Bbl)		Weighted- Average ($/Bbl)Weighted- Average ($/Bbl)Weighted- Average ($/Bbl)
Crude oil (WTI)819Apr. 2022-Jun. 2022$35.00 - $37.50$36.11 $48.38 - $51.10$49.97 $(39)
Crude oil (WTI)1,830Apr. 2022-Sep. 2022$— $40.00 $47.55 - $50.89$49.19 (85)
Crude oil (WTI)2,200Apr. 2022-Dec. 2022$— $57.00 $72.20 - $72.80$72.43 (50)
Crude oil (WTI Midland)(1)
728Apr. 2022-Jun. 2022$0.25 — 
Crude oil (WTI Midland)(1)
1,281Apr. 2022-Sep. 2022$0.38 (1)
Crude oil (WTI Midland)(1)
2,200Apr. 2022-Dec. 2022$0.05 (2)
Crude oil (WTI)364Apr. 2022-Jun. 2022$(0.20)(1)
Crude oil (WTI)1,281Apr. 2022-Sep. 2022$0.10 (2)
$(180)

(1)The index price is WTI Midland as quoted by Argus Americas Crude.
The amounts set forth in the table above represent our total unrealized derivative position at September 30, 2017March 31, 2022 and exclude the impact of non-performance risk. Non-performance risk is considered in the fair value of our derivative instruments that are recorded in our Condensed Consolidated Financial Statements and is primarily evaluated by reviewing credit default swap spreads for the various financial institutions with which we have derivative contracts, while our non-performance risk is evaluated using a market credit spread provided by oneseveral of our banks.
Subsequent event. In April 2022, we entered into the following financial commodity derivatives:
   Swaps
Type of ContractVolume (Mmbtu)Contract PeriodWeighted-Average
($/Mmbtu)
Natural gas (Waha)(1)
9,200,000May 2022 - Oct 2022$4.77 

(1)The index price is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.
Collars
FloorCeilingBasis Swaps
Type of ContractVolume (Mbbl)Contract PeriodRange
($/Bbl)		Weighted-Average
($/Bbl)		Range
($/Bbl)		Weighted-Average
($/Bbl)		Weighted-Average
($/Bbl)
Crude oil (WTI)920Oct. 2022 - Dec. 2022$— $65.00 $136.25 - $145.25$140.49 
Crude oil (WTI)1,810Jan. 2023 - Jun 2023$— $65.00 $116.30 - $118.30$117.47 
Crude oil (WTI Midland)(1)
920Oct. 2022 - Dec. 2022$0.64 
Crude oil (WTI Midland)(1)
1,810Jan. 2023 - Jun 2023$0.64 

(1)The index price is WTI Midland as quoted by Argus Americas Crude.

A significant portion of our expected oil and natural gas production for 2022 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable.
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During the first ninethree months of 2017, natural gas collars with floor prices of $3.09 per Mcf and ceiling prices ranging from $3.42 to $3.45 per Mcf covered 26.5 Bcf, or 5%, of natural gas production at an average price of $3.23 per Mcf. Natural gas swaps covered 38.3 Bcf, or 8%, of natural gas production at an average price of $3.23 per Mcf. Crude2022, oil collars with floor prices of $50.00ranging from $35.00 to $57.00 per Bbl and ceiling prices ranging from $56.25$45.15 to $56.50$72.80 per Bbl covered 1.4 Mmbbl,3.1 Mmbbls, or 43%,41 percent, of crude oil production at an averagea weighted-average price of $50.77$54.06 per Bbl. Oil basis swaps covered 2.7 Mmbbls, or 36 percent, of oil production at a weighted-average price of $0.20 per Bbl. Oil roll differential swaps covered 1.4 Mmbbls, or 19 percent, of oil production at a weighted-average price of $(0.07) per Bbl.
During the first three months of 2022, natural gas collars with floor prices ranging from $1.70 to $4.75 per Mmbtu and ceiling prices ranging from $2.10 to $10.32 per Mmbtu covered 55.1 Bcf, or 22 percent of natural gas production at a weighted-average price of $4.06 per Mmbtu.
We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of oil and natural gas and crude oil.gas. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of

oil and natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that our management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.
The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted by both by production and by changes in the future commodity prices. SeeRefer to “Forward-Looking Information” for further details.
Interest Rate Risk
At March 31, 2022, we had total debt of $3.1 billion (with a principal amount of $2.9 billion). All of our outstanding debt is based on fixed interest rates and, as a result, we do not have significant exposure to movements in market interest rates with respect to such debt. Our revolving credit facility provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of March 31, 2022 and, therefore, no related exposure to interest rate risk.
Fair Value of Other Financial Instruments
The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amountamounts reported in the Condensed Consolidated Balance Sheet for cash, and cash equivalents approximatesand restricted cash approximate fair value due to the short-term maturities of these instruments.
The fair value of our senior notes is based on quoted market prices. We use available market data and valuation methodologies to estimate the fair value of debt.our private placement senior notes. The fair value of debtthe private placement senior notes is the estimated amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of allthe private placement senior notes and the revolving credit facility is based on interest rates currently available to us.
The carrying amount and fair value of debt is as follows:follow:
 March 31, 2022December 31, 2021
(In millions)Carrying
Amount		Estimated Fair
Value		Carrying
Amount		Estimated Fair
Value
Long-term debt$3,115 $2,999 $3,125 $3,163 
Current maturities(25)(25)— — 
Long-term debt, excluding current maturities$3,090 $2,974 $3,125 $3,163 

  September 30, 2017 December 31, 2016
(In thousands) 
Carrying
Amount
 
Estimated Fair
Value
 
Carrying
Amount
 
Estimated Fair
Value
Debt, net $1,521,551
 $1,536,360
 $1,520,530
 $1,463,643
Current maturities (237,000) (243,569) —
 —
Long-term debt, excluding current maturities $1,284,551
 $1,292,791
 $1,520,530
 $1,463,643
ITEM 4. Controls and Procedures
As of September 30, 2017,March 31, 2022, the Company carried out an evaluation, under the supervision and with the participation of the Company'sCompany’s management, including the Company'sCompany’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company'sCompany’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”)Exchange Act). Based upon that evaluation, the Chief Executive Officer and Chief
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Financial Officer concluded that the Company'sCompany’s disclosure controls and procedures are effective in all material respects,to provide reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
ThereDuring the quarter ended December 31, 2021, the Company completed its Merger with Cimarex. As part of the ongoing integration of the acquired business, the Company is in the process of incorporating the controls and related procedures of Cimarex. Other than incorporating Cimarex’s controls, there were no changes in the Company's internal control over financial reporting that occurred during the thirdfirst quarter of 20172022 that have materially affected, or are reasonably likely to materiallyhave a material effect on, the Company'sCompany’s internal control over financial reporting.


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PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
Legal Matters
The information set forth under the heading “Legal Matters” in Note 8 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this quarterly reportForm 10-Q is incorporated by reference in response to this item.
Environmental Matters
From time to time, we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. WhileAlthough we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $100,000.$300,000.
ITEM 1A. Risk Factors
For additional information aboutThe below risk factor updates a risk factor, and should be read in conjunction with the other risk factors, that affect us, seepreviously discussed in Part I, Item 1A of our Form 10-K. Additional risks and uncertainties, including risks and uncertainties not presently known to us, or that we currently deem immaterial, could also have an adverse effect on our business, financial condition or results of operations.
Commodity prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the oil, natural gas and NGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and NGLs that we can produce economically. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. For example, the WTI oil prices in 2021 ranged from a high of $84.65 to a low of $47.62 per Bbl and NYMEX natural gas prices in 2021 ranged from a high of $23.86 (during Winter Storm Uri) to a low of $2.43 per Mmbtu. Any substantial or extended decline in future commodity prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in commodity prices may cause us to delay or postpone a significant portion of our exploration and development projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility and limit our ability to execute aspects of our business plans. Refer to “Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations” in our Form 10-K under Part I, Item IA.
Wide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas and NGLs, market uncertainty and a variety of additional factors that are beyond our Annual Reportcontrol. These factors include but are not limited to the following:
•the levels and location of oil, natural gas and NGLs supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from our Marcellus Shale properties) on Form 10-Kthe global natural gas supply;
•the level of consumer demand for oil, natural gas and NGLs, which has been significantly impacted by the year ended December 31, 2016.COVID-19 pandemic, particularly during 2020;
•weather conditions and seasonal trends;
•political, economic or health conditions in oil, natural gas and NGL producing regions, including the Middle East, Africa, South America and the U.S., including for example, the impacts of local or international pandemics and disasters or events such as the global COVID-19 pandemic;
•geopolitical risks and sanctions, including as a result of the war in Ukraine and other actions that may impact demand and supply chains;
•the ability and willingness of the members of OPEC+ to agree to and maintain oil price and production controls;
•the price level and quantities of foreign imports;
•actions of governmental authorities;
•the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or local areas;
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•inventory storage levels and the cost and availability of storage and transportation of oil, natural gas and NGLs;
•the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;
•the price, availability and acceptance of alternative fuels;
•technological advances affecting energy consumption;
•speculation by investors in oil, natural gas and NGLs;
•variations between product prices at sales points and applicable index prices; and
•overall economic conditions, including the value of the U.S. dollar relative to other major currencies.

These factors and the volatile nature of the energy markets make it impossible to predict future commodity prices. If commodity prices decline significantly for a sustained period of time, the lower prices may cause us to reduce our planned drilling program or adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
OurShare repurchase activity during the quarter ended March 31, 2022 was as follows:

PeriodTotal Number of Shares Purchased
(In thousands)		Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
(In thousands) (1)
Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
(In millions) (2)
January 2022— $— — $1,250 
February 2022149 $22.39 149 $1,247 
March 2022 (3)
7,804 $24.26 7,804 $1,058 
Total7,953 7,953 

(1)In February 2022, our Board of Directors hasterminated the previously authorized a share repurchase program underand authorized a new share repurchase program, which we maywas announced on February 24, 2022. This new share repurchase program authorizes us to purchase sharesup to $1.25 billion of our common stock in privately negotiated transactions or in the open market, or in negotiated transactions. There is no expiration date associatedincluding under plans complying with Rule 10b5-1 under the authorization. The maximum numberExchange Act. We purchased 8.0 million common shares for $192 million during the quarter ended March 31, 2022.
(2)As of remainingMarch 31, 2022, we can purchase up to $1.1 billion of shares under the repurchase program.
(3)Includes 325,000 shares that may bewere purchased under the plan asfor $8 million prior to March 31, 2022 and settled in April 2022.

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Table of September 30, 2017 was 7.1 million shares.Contents
ITEM 6. Exhibits
Index to Exhibits
Exhibit
Number		Description
Exhibit
Number3.1
Description
3.2
4.1
4.2
4.3
10.1*
10.2*
31.1
31.2
32.1
101.INSInline XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCHInline XBRL Taxonomy Extension Schema Document.
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document.
101.LABInline XBRL Taxonomy Extension Label Linkbase Document.
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101.PREExhibit
Number		Description
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

_______________________________________________________________________________.
*Compensatory plan, contract or arrangement.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CABOT OIL & GAS CORPORATIONCOTERRA ENERGY INC.
(Registrant)
October 30, 2017May 3, 2022By:/s/ DAN O. DINGESTHOMAS E. JORDEN
Dan O. DingesThomas E. Jorden
Chairman, President and Chief Executive Officer and President
(Principal Executive Officer)
October 30, 2017May 3, 2022By:/s/ SCOTT C. SCHROEDER
Scott C. Schroeder
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
October 30, 2017May 3, 2022By:/s/ TODD M. ROEMER
Todd M. Roemer
Vice President and ControllerChief Accounting Officer
(Principal Accounting Officer)

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