Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-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, 20172022
or
¨
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to 
Commission file number: 1-34776

chrd-20220930_g1.jpg
Oasis Petroleum Inc.Chord Energy Corporation
(Exact name of registrant as specified in its charter)
Delaware80-0554627
Delaware80-0554627
(State or other jurisdiction of

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

Identification No.)
1001 Fannin Street, Suite 1500
Houston, Texas
77002
Houston, Texas77002
(Address of principal executive offices)(Zip Code)

(281) 404-9500
(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 StockCHRDThe Nasdaq Stock Market LLC
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 ¨☐
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 ¨☐
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”,filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer☒Accelerated filer☐
Large accelerated filerýAccelerated filer¨
Non-accelerated filer
o  (Do not check if a smaller reporting company)
☐		Smaller reporting company¨☐
Emerging growth company¨☐
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.  ¨☐ 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ¨☐ No ý☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes  ý   No  ¨
Number of shares of the registrant’s common stock outstanding at November 3, 2017: 237,315,583October 31, 2022: 41,606,204 shares.




OASIS PETROLEUM INC.
Table of Contents
CHORD ENERGY CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30,2017 2022
TABLE OF CONTENTS
Page
1
Item 1. — Financial Statements (Unaudited)
1
Condensed Consolidated Balance Sheets atSeptember 30, 20172022 and December 31, 20162021
1
Condensed Consolidated Statements of Operations for the Three and Nine Months EndedSeptember 30, 20172022 and 20162021
23
Condensed Consolidated StatementStatements of Changes in Stockholders’ Equity for the Three and Nine Months EndedSeptember 30, 20172022 and 2021
34
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 2022 and 20162021
46
Notes to Condensed Consolidated Financial Statements
58
1. Organization and Operations of the Company
8
2. Summary of Significant Accounting Policies
8
3. Revenue Recognition
10
4. Inventory
11
5. Additional Balance Sheet Information
11
6. Fair Value Measurements
12
7. Derivative Instruments
14
8. Property, Plant and Equipment
18
9.Acquisitions
18
10. Divestitures
21
11. Discontinued Operations
22
12. Investment in Unconsolidated Affiliate
24
13. Long-Term Debt
24
14. Asset Retirement Obligations
25
15. Income Taxes
26
16. Equity-Based Compensation
27
17. Stockholders’ Equity
28
18. Earnings (Loss) Per Share
30
19. Commitments and Contingencies
31
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
3233
Item 3. — Quantitative and Qualitative Disclosures About Market Risk
5047
Item 4. — Controls and Procedures
5249
5350
Item 1. — Legal Proceedings
5350
Item 1A. — Risk Factors
5350
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds
5452
Item 5.— Other Information
52
Item 6. — Exhibits
5452
5654





Table of Contents


EXPLANATORY NOTE
On July 1, 2022, Oasis Petroleum Inc. (“Oasis”) and Whiting Petroleum Corporation (“Whiting”) completed their previously announced merger of equals transaction pursuant to an Agreement and Plan of Merger dated March 7, 2022. Upon completion of the merger of equals, Oasis changed its name to Chord Energy Corporation (“Chord” or the “Company”). The merger was accounted for as of July 1, 2022 under the acquisition method of accounting in accordance with Financial Accounting Standards Board Accounting Standards Codification 805, Business Combinations. Accordingly, unless otherwise specifically noted herein, the periods prior to July 1, 2022 report the financial results of legacy Oasis, while the periods as of and subsequent to July 1, 2022 report the financial results of Chord, including the impacts from the merger of equals with Whiting.


Table of Contents
PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements (Unaudited)
Chord Energy Corporation
Condensed Consolidated Balance Sheets (Unaudited)
September 30, 2022December 31, 2021
 (In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents$658,857 $172,114 
Accounts receivable, net717,149 377,202 
Inventory60,956 28,956 
Prepaid expenses13,339 6,016 
Derivative instruments3,061 — 
Other current assets582 1,836 
Current assets held for sale— 1,029,318 
Total current assets1,453,944 1,615,442 
Property, plant and equipment
Oil and gas properties (successful efforts method)4,926,278 1,395,837 
Other property and equipment75,434 48,981 
Less: accumulated depreciation, depletion and amortization(345,648)(124,386)
Total property, plant and equipment, net4,656,064 1,320,432 
Derivative instruments52,110 44,865 
Investment in unconsolidated affiliate138,452 — 
Long-term inventory22,009 17,510 
Operating right-of-use assets26,954 15,782 
Deferred tax assets183,495 — 
Other assets22,107 12,756 
Total assets$6,555,135 $3,026,787 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable$32,709 $2,136 
Revenues and production taxes payable575,372 270,306 
Accrued liabilities476,636 150,674 
Accrued interest payable9,759 2,150 
Derivative instruments366,605 89,447 
Advances from joint interest partners3,609 1,892 
Current operating lease liabilities11,870 7,893 
Other current liabilities12,205 1,046 
Current liabilities held for sale— 699,653 
Total current liabilities1,488,765 1,225,197 
Long-term debt393,782 392,524 
Deferred tax liabilities— 7 
Asset retirement obligations119,757 57,604 
Derivative instruments37,898 115,282 
Operating lease liabilities14,380 6,724 
Other liabilities29,740 7,876 
1
Table of Contents
Oasis Petroleum Inc.
Condensed Consolidated Balance Sheets
(Unaudited)
 September 30, 2017 December 31, 2016
 (In thousands, except share data)
ASSETS   
Current assets   
Cash and cash equivalents$8,488
 $11,226
Accounts receivable, net285,383
 204,335
Inventory17,169
 10,648
Prepaid expenses10,647
 7,623
Derivative instruments692
 362
Other current assets65
 4,355
Total current assets322,444
 238,549
Property, plant and equipment   
Oil and gas properties (successful efforts method)7,640,785
 7,296,568
Other property and equipment783,542
 618,790
Less: accumulated depreciation, depletion, amortization and impairment(2,388,709) (1,995,791)
Total property, plant and equipment, net6,035,618
 5,919,567
Derivative instruments703
 —
Long-term inventory10,885
 —
Other assets21,562
 20,516
Total assets$6,391,212
 $6,178,632
LIABILITIES AND STOCKHOLDERS’ EQUITY   
Current liabilities   
Accounts payable$16,348
 $4,645
Revenues and production taxes payable169,361
 139,737
Accrued liabilities194,157
 119,173
Accrued interest payable20,325
 39,004
Derivative instruments16,412
 60,469
Advances from joint interest partners5,095
 7,597
Other current liabilities—
 10,490
Total current liabilities421,698
 381,115
Long-term debt2,340,613
 2,297,214
Deferred income taxes508,335
 513,529
Asset retirement obligations52,413
 48,985
Derivative instruments3,703
 11,714
Other liabilities5,805
 2,918
Total liabilities3,332,567
 3,255,475
Commitments and contingencies (Note 15)
 
Stockholders’ equity   
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,639,488 shares issued and 237,312,881 shares outstanding at September 30, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 20162,348
 2,331
Treasury stock, at cost: 1,326,607 and 856,892 shares at September 30, 2017 and December 31, 2016, respectively(22,132) (15,950)
Additional paid-in capital2,369,098
 2,345,271
Retained earnings593,368
 591,505
Oasis share of stockholders’ equity2,942,682
 2,923,157
Non-controlling interests115,963
 —
Total stockholders’ equity3,058,645
 2,923,157
Total liabilities and stockholders’ equity$6,391,212
 $6,178,632

Total liabilities2,084,322 1,805,214 
Commitments and contingencies (Note 19)
Stockholders’ equity
Common stock, $0.01 par value: 120,000,000 shares authorized, 43,601,102 shares issued and 41,555,328 shares outstanding at September 30, 2022; 60,000,000 shares authorized, 20,147,199 shares issued and 19,276,181 shares outstanding at December 31, 2021438 200 
Treasury stock, at cost: 2,045,774 shares at September 30, 2022 and 871,018 shares at December 31, 2021(224,845)(100,000)
Additional paid-in capital3,469,622 863,010 
Retained earnings1,225,598 269,690 
Chord share of stockholders’ equity4,470,813 1,032,900 
Non-controlling interests— 188,673 
Total stockholders’ equity4,470,813 1,221,573 
Total liabilities and stockholders’ equity$6,555,135 $3,026,787 
The accompanying notes are an integral part of these condensed consolidated financial statements.

2
Oasis Petroleum Inc.
Table of Contents
Chord Energy Corporation
Condensed Consolidated Statements of Operations (Unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (In thousands, except per share data)
Revenues
Oil, NGL and gas revenues$1,056,146 $281,474 $2,088,215 $781,459 
Purchased oil and gas sales132,697 87,382 542,653 276,349 
Other services revenues— 121 324 542 
Total revenues1,188,843 368,977 2,631,192 1,058,350 
Operating expenses
Lease operating expenses156,397 44,889 287,195 146,373 
Other services expenses— 26 123 47 
Gathering, processing and transportation expenses35,549 30,028 99,759 90,920 
Purchased oil and gas expenses132,625 85,828 546,310 275,789 
Production taxes83,535 18,445 159,473 50,933 
Depreciation, depletion and amortization141,047 23,975 227,856 83,976 
Exploration and impairment910 263 1,698 1,941 
General and administrative expenses102,226 20,088 151,415 61,500 
Total operating expenses652,289 223,542 1,473,829 711,479 
Gain on sale of assets755 5,405 2,595 228,473 
Operating income537,309 150,840 1,159,958 575,344 
Other income (expense)
Net gain (loss) on derivative instruments337,409 (101,790)(128,766)(550,342)
Net gain from investment in unconsolidated affiliate75,093 — 38,977 — 
Interest expense, net of capitalized interest(8,645)(7,156)(22,810)(23,444)
Other income (expense)(864)(139)2,186 (793)
Total other income (expense), net402,993 (109,085)(110,413)(574,579)
Income from continuing operations before income taxes940,302 41,755 1,049,545 765 
Income tax benefit1,307 — 3,352 — 
Net income from continuing operations941,609 41,755 1,052,897 765 
Income (loss) from discontinued operations attributable to Chord, net of income tax(59,858)30,195 425,696 100,957 
Net income attributable to Chord$881,751 $71,950 $1,478,593 $101,722 
Basic earnings attributable to Chord per share:
Basic from continuing operations$22.79 $2.11 $39.28 $0.04 
Basic from discontinued operations(1.45)1.52 15.88 5.07 
Basic total (Note 18)$21.34 $3.63 $55.16 $5.11 
Diluted earnings attributable to Chord per share:
Diluted from continuing operations$21.84 $2.01 $37.02 $0.04 
Diluted from discontinued operations(1.39)1.45 14.97 4.92 
Diluted total (Note 18)$20.45 $3.46 $51.99 $4.96 
Weighted average shares outstanding:
Basic (Note 18)41,318 19,812 26,806 19,905 
Diluted (Note 18)43,107 20,786 28,438 20,508 
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Table of Contents

Chord Energy Corporation
Condensed Consolidated Statements of Operations
Changes in Stockholders’ Equity (Unaudited)
Attributable to Chord
 Common StockTreasury StockAdditional
Paid-in Capital		Retained EarningsNon-controlling InterestsTotal
Stockholders’
Equity
SharesAmountSharesAmount
(In thousands)
Balance as of December 31, 202119,276 $200 871 $(100,000)$863,010 $269,690 $188,673 $1,221,573 
Equity-based compensation94 — — — 4,800 — 48 4,848 
Tax withholding on vesting of equity-based awards(31)— 31 (4,132)— — — (4,132)
Modification of equity-based awards— — — — (226)— — (226)
Dividends ($3.585 per share)— — — — — (73,074)— (73,074)
Warrants exercised233 3 — — 15,689 — — 15,692 
Net income— — — — — 466,003 2,311 468,314 
OMP Merger— — — — — — (191,032)(191,032)
Balance as of March 31, 202219,572 203 902 (104,132)883,273 662,619 — 1,441,963 
Equity-based compensation11 — — — 4,815 — — 4,815 
Tax withholding on vesting of equity-based awards(4)— 4 (657)— — — (657)
Transfer of equity plan shares from treasury— — (35)4,789 (4,789)— — — 
Dividends ($3.525 per share)— — — — — (71,961)— (71,961)
Special dividend ($15.00 per share)— — — — — (307,408)— (307,408)
Warrants exercised84 3 — — 502 — — 505 
Net income— — — — — 130,839 — 130,839 
Balance as of June 30, 202219,663 206 871 (100,000)883,801 414,089 — 1,198,096 
Shares issued in Merger22,672 227 — �� 2,477,809 — — 2,478,036 
Replacement equity awards issued in Merger— — — — 27,402 — — 27,402 
Replacement warrants issued in Merger— — — — 79,774 — — 79,774 
Equity-based compensation626 4 — — 30,684 — — 30,688 
Tax withholding on vesting of equity-based awards(286)— — — (31,979)— — (31,979)
Dividends ($1.25 per share)— — — — — (70,242)— (70,242)
Share repurchases(1,175)— 1,175 (124,845)— — — (124,845)
Warrants exercised55 1 — — 2,131 — — 2,132 
Net income— — — — — 881,751 — 881,751 
Balance as of September 30, 202241,555 $438 2,046 $(224,845)$3,469,622 $1,225,598 $— $4,470,813 
The accompanying notes are an integral part of these condensed consolidated financial statements.

4
Table of Contents
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands, except per share data)
Revenues       
Oil and gas revenues$248,648
 $156,316
 $704,533
 $432,968
Bulk oil sales21,195
 1,867
 56,917
 1,867
Midstream revenues18,767
 8,487
 48,939
 22,380
Well services revenues16,138
 10,641
 33,566
 29,459
Total revenues304,748
 177,311
 843,955
 486,674
Operating expenses       
Lease operating expenses45,334
 35,696
 133,871
 98,283
Midstream operating expenses4,301
 2,617
 10,891
 6,095
Well services operating expenses9,125
 5,548
 21,115
 15,334
Marketing, transportation and gathering expenses15,028
 7,003
 38,018
 22,046
Bulk oil purchases21,701
 1,853
 57,683
 1,853
Production taxes21,052
 14,638
 60,322
 39,758
Depreciation, depletion and amortization132,289
 111,948
 384,246
 356,885
Exploration expenses854
 489
 4,010
 1,192
Impairment139
 382
 6,021
 3,967
General and administrative expenses22,531
 22,845
 69,913
 69,087
Total operating expenses272,354
 203,019
 786,090
 614,500
Gain (loss) on sale of properties—
 6
 —
 (1,305)
Operating income (loss)32,394
 (25,702) 57,865
 (129,131)
Other income (expense)       
Net gain (loss) on derivative instruments(54,310) 20,847
 52,297
 (55,624)
Interest expense, net of capitalized interest(37,389) (31,726) (110,548) (105,444)
Gain (loss) on extinguishment of debt—
 (13,793) —
 4,865
Other income (expense)(605) (259) (755) 188
Total other expense(92,304) (24,931) (59,006) (156,015)
Loss before income taxes(59,910) (50,633) (1,141) (285,146)
Income tax benefit18,846
 16,691
 470
 96,818
Net loss including non-controlling interests(41,064) (33,942) (671) (188,328)
Less: Net income attributable to non-controlling interests150
 —
 150
 —
Net loss attributable to Oasis$(41,214) $(33,942) $(821) $(188,328)
Earnings (loss) attributable to Oasis per share:       
Basic (Note 13)$(0.18) $(0.19) $0.00
 $(1.09)
Diluted (Note 13)(0.18) (0.19) 0.00
 (1.09)
Weighted average shares outstanding:       
Basic (Note 13)233,389
 177,120
 233,248
 172,360
Diluted (Note 13)233,389
 177,120
 233,248
 172,360
Chord Energy Corporation

Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited) (Continued)
Attributable to Chord
 Common StockTreasury StockAdditional
Paid-in Capital		Retained Earnings (Accumulated Deficit)Non-controlling InterestsTotal
Stockholders’
Equity
SharesAmountSharesAmount
(In thousands)
Balance as of December 31, 202020,093 $200 — $— $965,654 $(49,912)$96,797 $1,012,739 
Equity-based compensation— — — — 1,709 — 489 2,198 
Dividends ($0.375 per share)— — — — (7,535)— — (7,535)
Distributions to non-controlling interest owners— — — — — — (6,029)(6,029)
Midstream Simplification— — — — 2,358 — (2,358)— 
Common control transaction costs— — — — (4,111)— — (4,111)
Warrants exercised— — — — 6 — — 6 
Net income (loss)— — — — — (43,592)8,327 (35,265)
Balance as of March 31, 202120,093 200 — — 958,081 (93,504)97,226 962,003 
Equity-based compensation— — — — 4,688 — 14 4,702 
Dividends ($0.375 per share)— — — — (8,090)— — (8,090)
Special dividend ($4.00 per share)— — — — (82,958)— — (82,958)
Distributions to non-controlling interest owners— — — — — — (6,136)(6,136)
Repurchase of common stock(191)— 191 (14,560)— — — (14,560)
Issuance of OMP common units, net of offering costs— — — — — — 86,657 86,657 
Warrants exercised2 — — — 167 — — 167 
Common control transaction costs— — — — (1,321)— — (1,321)
Net income— — — — — 73,364 7,945 81,309 
Balance as of June 30, 202119,904 200 191 (14,560)870,567 (20,140)185,706 1,021,773 
Equity-based compensation— — — — 4,143 — 144 4,287 
Dividends ($0.375 per share)— — — — (7,765)— — (7,765)
Distributions to non-controlling interest owners— — — — — — (8,278)(8,278)
Warrants exercised1 — — — 68 — — 68 
Common control transaction costs— — — — (21)— — (21)
Other— — — — — — (65)(65)
Net income— — — — — 71,950 11,382 83,332 
Balance as of September 30, 202119,905 $200 191 $(14,560)$866,992 $51,810 $188,889 $1,093,331 
The accompanying notes are an integral part of these condensed consolidated financial statements.

5

Table of Contents
Oasis Petroleum Inc.Chord Energy Corporation
Condensed Consolidated StatementStatements of Changes in Stockholders’ Equity
Cash Flows (Unaudited)
Nine Months Ended September 30,
 20222021
 (In thousands)
Cash flows from operating activities:
Net income including non-controlling interests$1,480,904 $129,376 
Adjustments to reconcile net income including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization227,856 112,581 
Gain on sale of assets(521,495)(228,473)
Impairment1,073 5 
Deferred income taxes66,668 — 
Net loss on derivative instruments128,766 550,342 
Net gain from investment in unconsolidated affiliate(38,977)— 
Equity-based compensation expenses40,351 11,187 
Deferred financing costs amortization and other1,241 18,811 
Working capital and other changes:
Change in accounts receivable, net(13,007)(65,324)
Change in inventory2,199 2,408 
Change in prepaid expenses7,708 4,509 
Change in accounts payable, interest payable and accrued liabilities57,581 118,942 
Change in other assets and liabilities, net4,766 (9,618)
Net cash provided by operating activities1,445,634 644,746 
Cash flows from investing activities:
Capital expenditures(303,140)(143,201)
Acquisitions, net of cash acquired(148,363)(74,500)
Proceeds from divestitures, net of cash divested155,728 373,892 
Costs related to divestitures(11,368)(2,785)
Derivative settlements(487,394)(242,437)
Proceeds from sale of investment in unconsolidated affiliate428,231 — 
Distributions from investment in unconsolidated affiliate40,607 — 
Net cash used in investing activities(325,699)(89,031)
Cash flows from financing activities:
Proceeds from revolving credit facilities1,035,000 384,500 
Principal payments on revolving credit facilities(1,020,000)(884,500)
Proceeds from issuance of senior unsecured notes— 850,000 
Cash paid to settle Whiting debt(2,154)— 
Deferred financing costs(3,938)(20,480)
Proceeds from issuance of OMP common units, net of offering costs— 86,592 
Common control transaction costs— (5,453)
Purchases of treasury stock(124,845)(14,560)
Tax withholding on vesting of equity-based awards(36,768)— 
Dividends paid(500,106)(102,123)
Distributions to non-controlling interests— (20,443)
Payments on finance lease liabilities(570)(1,107)
Proceeds from warrants exercised17,520 241 
Net cash provided by (used in) financing activities(635,861)272,667 
Increase in cash and cash equivalents484,074 828,382 
6
Table of Contents
 Attributable to Oasis    
 Common Stock Treasury Stock 
Additional
Paid-in Capital
 Retained Earnings Non-controlling Interests 
Total
Stockholders’
Equity
Shares Amount Shares Amount 
 (In thousands)
Balance at December 31, 2016236,344
 $2,331
 857
 $(15,950) $2,345,271
 $591,505
 $—
 $2,923,157
Cumulative-effect adjustment for adoption of ASU 2016-09 (Note 2)—
 —
 —
 —
 2,040
 2,684
 —
 4,724
Fees (2016 issuance of common stock)—
 —
 —
 —
 (55) —
 —
 (55)
Equity-based compensation1,439
 17
 —
 —
 21,842
 —
 —
 21,859
Issuance of Oasis Midstream common units, net of offering costs—
 —
 —
 —
 —
 —
 115,813
 115,813
Treasury stock - tax withholdings(470) —
 470
 (6,182) —
 —
 —
 (6,182)
Net income (loss)—
 —
 —
 —
 —
 (821) 150
 (671)
Balance at September 30, 2017237,313
 $2,348
 1,327
 $(22,132) $2,369,098
 $593,368
 $115,963
 $3,058,645

Cash and cash equivalents:
Beginning of period174,783 20,226 
End of period$658,857 $848,608 
Supplemental non-cash transactions:
Change in accrued capital expenditures$41,348 $13,014 
Change in asset retirement obligations412 (389)
Non-cash consideration exchanged in Merger2,585,211 — 
Investment in unconsolidated affiliate568,312 — 
Note receivable from divestiture— 2,900 
Contingent consideration from Permian Basin Sale— 32,860 
Dividends payable27,256 — 
The accompanying notes are an integral part of these condensed consolidated financial statements.

7

Oasis Petroleum Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
 Nine Months Ended September 30,
 2017 2016
 (In thousands)
Cash flows from operating activities:   
Net loss including non-controlling interests$(671) $(188,328)
Adjustments to reconcile net loss to net cash provided by operating activities:   
Depreciation, depletion and amortization384,246
 356,885
Gain on extinguishment of debt—
 (4,865)
Loss on sale of properties—
 1,305
Impairment6,021
 3,967
Deferred income taxes(470) (96,818)
Derivative instruments(52,297) 55,624
Equity-based compensation expenses20,451
 18,761
Deferred financing costs amortization and other12,666
 10,174
Working capital and other changes:   
Change in accounts receivable(81,022) 11,349
Change in inventory(235) 2,559
Change in prepaid expenses823
 1,168
Change in other current assets276
 (240)
Change in long-term inventory and other assets(12,843) (148)
Change in accounts payable, interest payable and accrued liabilities32,282
 (41,991)
Change in other current liabilities(10,490) (6,000)
Change in other liabilities—
 17
Net cash provided by operating activities298,737
 123,419
Cash flows from investing activities:   
Capital expenditures(443,649) (340,314)
Proceeds from sale of properties4,000
 12,333
Costs related to sale of properties—
 (310)
Derivative settlements(804) 115,576
Advances from joint interest partners(2,502) 544
Net cash used in investing activities(442,955) (212,171)
Cash flows from financing activities:   
Proceeds from revolving credit facility764,000
 835,000
Principal payments on revolving credit facility(732,000) (778,000)
Repurchase of senior unsecured notes—
 (435,907)
Proceeds from issuance of senior unsecured convertible notes—
 300,000
Deferred financing costs(96) (8,811)
Proceeds from sale of common stock—
 182,791
Proceeds from sale of Oasis Midstream common units, net of offering costs115,813
 —
Purchases of treasury stock(6,182) (2,275)
Other(55) —
Net cash provided by financing activities141,480
 92,798
Increase (decrease) in cash and cash equivalents(2,738) 4,046
Cash and cash equivalents:   
Beginning of period11,226
 9,730
End of period$8,488
 $13,776
Supplemental non-cash transactions:   
Change in accrued capital expenditures$63,499
 $(49,177)
Change in asset retirement obligations3,112
 (8,083)
Notes payable from acquisition4,875
 —
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The accompanying notes are an integral part of these condensed consolidated financial statements.

OASIS PETROLEUM INC.Chord Energy Corporation
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. Organization and Operations of the Company
Oasis Petroleum Inc.Chord Energy Corporation (together with its consolidated subsidiaries, “Oasis”the “Company” or the “Company”“Chord”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production (“E&P”) company focused on the acquisitionwith quality and development of unconventional oil and natural gas resourcessustainable long-lived assets in the North Dakota and Montana regions of the Williston Basin. The Company, formerly known as Oasis Petroleum North America LLCInc. (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties. The Company also operates a midstream services business through OMS Holdings LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”Oasis”), bothwas established upon completion of which are separate reportable business segments that are complementary to its primary development and production activities.the Merger (defined below) with Whiting Petroleum Corporation (“Whiting”).
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 20162021 is derived from audited financial statements. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement of the Company’s financial position, have been included. Management has made certain estimates and assumptions that affect reported amounts in the unaudited condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.
These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 20162021 (“20162021 Annual Report”).
The Merger
On March 7, 2022, Oasis and Whiting entered into an Agreement and Plan of Merger (the “Merger Agreement”), which provided for, among other things, the combination of Oasis and Whiting in a merger of equals transaction (the “Merger”). Whiting was an independent oil and gas company engaged in the development, production and acquisition of crude oil, natural gas liquid (“NGL”) and natural gas primarily in the Rocky Mountains region of the United States.
In connection with the third quarterMerger, the Board of 2017Directors of Oasis unanimously (i) determined the issuance of the shares of common stock, par value $0.01 per share, of Oasis (the “Oasis Stock Issuance”), and the amendment of Oasis’ restated certificate of incorporation to (a) increase the number of authorized shares of common stock from 60,000,000 shares of common stock to 120,000,000 shares of common stock and (b) change the name of the Company from Oasis Petroleum Inc. to Chord Energy Corporation (the “Oasis Charter Amendment”) are fair to, and in the best interests of, Oasis and the holders of its common stock, (ii) approved and declared advisable the Oasis Stock Issuance and the Oasis Charter Amendment and (iii) recommended that the holders of common stock approve the Oasis Stock Issuance and the Oasis Charter Amendment. On June 28, 2022, all proposals relating to the Merger, including the Oasis Stock Issuance and Oasis Charter Amendment proposals, were approved by the shareholders of Oasis and Whiting.
Under the terms of the Merger Agreement, each holder of Whiting common stock received 0.5774 shares of Chord common stock (the “Share Consideration”) and $6.25 per share in cash (the “Cash Consideration” and together with the Share Consideration, the “Merger Consideration”) in exchange for each share of Whiting common stock.
The Merger was completed on July 1, 2022 and has been accounted for under the acquisition method of accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC 805”). Oasis was treated as the acquirer for accounting purposes. Under the acquisition method of accounting, the assets and liabilities of Whiting have been recorded at their respective fair values as of the acquisition date on July 1, 2022. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after July 1, 2022. See Note 9—Acquisitions for additional information.

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Discontinued Operations
On February 1, 2022, the Company completed the OMP Merger (defined in Note 10—Divestitures). The OMP Merger represented a strategic shift for the Company and qualified for reporting as a discontinued operation in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations (“ASC 205-20”). Accordingly, the results of operations of Oasis Midstream Partners LP (“OMP” or “Oasis Midstream”), a subsidiary for the period prior to closing on February 1, 2022 were classified as discontinued operations in the Condensed Consolidated Statement of OMS, completed its initial public offering (“IPO”)Operations for the nine months ended September 30, 2022. Prior periods have been recast so that the basis of common units representing limited partner interests. As a result, the Company’s consolidated financial statements present a non-controlling interest section, which represents the public’s ownership in OMP. See Note 3 – Oasis Midstream Partners LP for further discussionpresentation is consistent with that of the OMP IPO.
Consolidation. The accompanying2022 condensed consolidated financial statements ofstatements. In addition, the Company include the accounts of Oasis, the accounts of wholly-owned subsidiaries,assets and the accountsliabilities of OMP which is considered a variable interest entity (“VIE”)were classified as held for whichsale in the Company is the primary beneficiary. All significant intercompany balances and transactions have been eliminated upon consolidation.
Condensed Consolidated VIE. Balance Sheet at December 31, 2021. The Company has determined that the partners with equity at risk in OMP lack the authority, through voting rights or similar rights,Condensed Consolidated Statements of Cash Flows were not required to direct the activities that most significantly impact OMP’s economic performance. Therefore, as the limited partners of OMP do not have substantive kick-out or substantive participating rights over OMP GP LLC (“OMP GP”), the general partner to OMP, OMP is a VIE. Through the Company’s ownership interest in OMP GP, the Company has the authority to direct the activities that most significantly affect economic performance and the right to receive benefits that could be potentially significant to OMP. Therefore, the Company is considered the primary beneficiary and consolidates OMP and records a non-controlling interestreclassified for the interest owned by the public as of September 30, 2017.discontinued operations for any period. See Note 11—Discontinued Operations for additional information.
Risks and Uncertainties
As ana producer of crude oil, NGLs and natural gas, producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, andNGLs or natural gas prices will not be subject to wide fluctuations in the future. AnA substantial or extended period of lowdecline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, andthe quantities of crude oil, NGLs and natural gas reserves that may be economically produced.produced and the Company’s access to capital.

Cash Equivalents
The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents. While the Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation, the Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts.
The following table provides a reconciliation of cash and cash equivalents reported within the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows:
September 30, 2022December 31, 2021
(In thousands)
Cash and cash equivalents$658,857 $172,114 
Cash and cash equivalents classified as held for sale— 2,669 
Total cash and cash equivalents$658,857 $174,783 
Significant Accounting Policies
There have been no material changes to the Company’s criticalsignificant accounting policies and estimates from those disclosed in the 20162021 Annual Report, other thanexcept as noted below.follows:
Equity-based compensation. In the first quarter of 2017,Investment in unconsolidated affiliate. On February 1, 2022, the Company adopted Accounting Standards Update No. 2016-09, Improvementscompleted the OMP Merger (defined in Note 10—Divestitures) and received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”). In addition, the Company and Crestwood executed a director nomination agreement pursuant to Employee Share-Based Payment Accountingwhich the Company initially appointed two directors to the Board of Directors of Crestwood Equity GP LLC, a Delaware limited liability company and the general partner of Crestwood (“ASU 2016-09”Crestwood GP”), which updates several aspects. On September 15, 2022, both directors resigned from the Board of Directors of Crestwood GP in connection with the completion of the accountingsale of 16,000,000 Crestwood common units and pursuant to the terms of the director nomination agreement. The Company has elected to account for share-based payment transactions, including recognitionits investment in Crestwood using the fair value option under FASB ASC 825-10, Financial Instruments. Under the fair value option, the Company measures the carrying amount of excess tax benefits and deficiencies, the classification of those excess tax benefitsits investment in Crestwood at fair value each reporting period, with changes in fair value recorded to net gain from investment in unconsolidated affiliate on the statementCondensed Consolidated Statement of Operations. Cash distributions from Crestwood are recorded to net gain from investment in unconsolidated affiliate on the Condensed Consolidated Statement of Operations and distributions from investment in unconsolidated affiliate on the Condensed Consolidated Statement of Cash Flows. See Note 6—Fair Value Measurements and Note 12—Investment in Unconsolidated Affiliate for additional information.
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Business combinations. The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed measured at the estimated acquisition date fair value. Transaction and integration costs associated with business combinations are expensed as incurred.
The Company makes various assumptions in estimating the fair value of the assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair value of proved and unproved oil and gas properties, which is measured using valuation techniques that convert future cash flows an accounting policy electionto a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital. In addition, when appropriate, the Company reviews comparable transactions between market participants for forfeitures,the purchase and sale of oil and gas properties within the same region to measure fair value, which illustrates the amount an employer can withhold to cover income taxesa willing buyer and still qualifyseller would enter into in exchange for equity classification andsuch properties.
The Company records goodwill for any amount of the classification of those taxes paid on the statement of cash flows. In accordance with the new guidance, the Company recorded a $2.7 million cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet as of September 30, 2017, which included recognition ofconsideration transferred in excess tax benefits and deficiencies and the removal of the estimated forfeiture rate. ASU 2016-09 was appliedfair value of the net assets acquired and a bargain purchase gain for any amount of the estimated fair value of net assets acquired in excess of the consideration transferred. Deferred taxes are recorded for any difference between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on a modified retrospectiveavailable information concerning the tax basis of assets acquired and prior periods were not retrospectively adjusted.
Inventory. Inliabilities assumed and loss carryforwards at the first quarter of 2017,acquisition date, although such estimates may change in the Company adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), which changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impactfuture as a result of adoption as of September 30, 2017.additional information becomes known.
Recent Accounting Pronouncements
Revenue recognition. Reference rate reform.In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015,March 2020, the FASB issued Accounting Standards Update No. 2015-14, Deferral2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effective DateEffects of Reference Rate Reform on Financial Reporting (“ASU 2015-14”2020-04”). ASU 2015-14 defers2020-04 provides optional guidance for a limited time to ease the potential burden in accounting for reference rate reform, including optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. ASU 2020-04 applies only to contracts and hedging relationships that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued due to reference rate reform. ASU 2020-04 is effective dateimmediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. On July 1, 2022, the Company entered into the Amended and Restated Credit Agreement to, among other things, provide for the replacement of LIBOR with the new revenue standardSecured Overnight Financing Rate (“SOFR”), an index supported by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016 and 2017, the FASB issued additional accounting standards updates to clarify the implementation guidanceshort-term Treasury repurchase agreements. The replacement of ASU 2014-09. In order to evaluate theLIBOR with SOFR did not have a material impact that the adoption of ASU 2014-09 will have on the Company’s financial position, cash flows and results of operations, the Company has initiated a comprehensive review of the significant revenue streams across all reportable segments. The Company has formed an implementation team, completed training on the new standard and is assessing the impact of the five-step model of the new standard on its contracts with customers. Currently, the Company cannot reasonably estimate the impact the application of ASU 2014-09 will have upon its consolidated financial statements butand related disclosures. See Note 13—Long-Term Debt for additional information.
3. Revenue Recognition
Revenues from contracts with customers were as follows for the periods presented:
Three Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (In thousands)
Crude oil revenues$824,265 $205,731 $1,629,033 $598,278 
Purchased crude oil sales82,902 53,562 415,838 183,523 
NGL and natural gas revenues231,881 75,743 459,182 183,181 
Purchased NGL and natural gas sales49,795 33,820 126,815 92,826 
Other services revenues— 121 324 542 
Total revenues$1,188,843 $368,977 $2,631,192 $1,058,350 
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The Company records revenue when the performance obligations under the terms of its customer contracts are satisfied. For sales of commodities, the Company expectsrecords revenue in the month the production or purchased product is delivered to adopt ASU 2014-09 using the modified retrospective approach as permitted bypurchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the FASB. The Company continues to assess the impact of ASU 2014-09, along with industry trends and additional interpretive guidance, on its core revenue streams,date production is delivered, and as a result, of the continued assessment, the Company may modify its plan of adoption accordingly.
Financial instruments. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Statement of cash flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations, but could result in presentation changes on the Company’s statement of cash flows.

Income taxes. In October 2016, the FASB issued Accounting Standards Update No. 2016-16, Intra-Entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Business combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Equity-based compensation. In May 2017, the FASB issued Accounting Standards Update No. 2017-09, Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The adoption of ASU 2017-09 will become effective for annual periods beginning after December 15, 2017, and the Company is currently evaluating the impact that it will have on its financial position, cash flows and results of operations.
3. Oasis Midstream Partners LP
Oasis Midstream Partners LP 
OMP is a growth-oriented, fee-based master limited partnership formed by the Companyrequired to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the oil and natural gas operations of Oasis and are strategically positioned to capture volumes from other producers.
Initial Public Offering of Oasis Midstream Partners LP 
On September 25, 2017, OMP completed its IPO of 7,500,000 common units representing limited partner interests in OMP at a price to the public of $17.00 per common unit ($15.98 per common unit, net of underwriting discounts and commisions). OMP received net proceeds from the IPO of approximately $115.8 million after deducting underwriting discounts, structuring fees and estimated offering expenses and distributed $113.7 million of the net proceeds to Oasis during the third quarter of 2017. Pursuant to the underwriting agreement, OMP granted the underwriters a 30-day option to purchase up to an aggregate of 1,125,000additional common units (the “Underwriters’ Option”) on the same terms, which was exercised in full on October 10, 2017 and resulted in additional net proceeds of approximately $17.9 million after deducting underwriting discounts and structuring fees. OMP distributed the additional net proceeds of approximately $17.9 million from the Underwriters’ Option to Oasis on October 10, 2017. The common units are traded on the New York Stock Exchange under the symbol OMP.
In exchange for contributed assets, Oasis received 5,125,000 common units and13,750,000 subordinated units, representing a limited partner interest in OMP and the right to receive cash distributions from OMP. In addition to and concurrent with the closing of the IPO, OMP GP retained a non-economic general partnership interest and was issued incentive distribution rights in OMP.
Class B Units in OMP General Partner LLC
On May 22, 2017, OMP GP granted restricted Class B Units to certain employees, including OMP’s executive officers, as consideration for services to Oasis, OMP GP, and OMP, which vest over a ten-year period. The restricted Class B Units represent 10% of the outstanding units of OMP GP. Compensation expense is recognized ratably over the requisite service period.

Contractual Arrangements
In connection with the OMP IPO, the Company entered into several 15-year, fee-based contractual arrangements with OMP for midstream services, including (i) gas gathering, compression, processing and gas lift services; (ii) crude gathering, stabilization, blending, storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply and distribution services. In addition, the Company provides substantial labor and overhead support for OMP. Upon completion of the OMP IPO, the Company entered into a 15-year services and secondment agreement with OMP pursuant to which the Company provides all personnel, equipment, electricity, chemicals and services (including third-party services) required for OMP to operate such assets, and OMP reimburses the Company for its share of the actual costs of operating such assets. In addition, pursuant to the services and secondment agreement, the Company performs centralized corporate, general and administrative services for OMP, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. The Company has also seconded to OMP certain of its employees to operate, construct, manage and maintain its assets, and OMP reimburses the Company for direct general and administrative expenses incurred by the Company for the provision of the above services. The expenses of executive officers and non-executive employees are allocated to OMP based onestimate the amount of time spent managingproduction that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its businessproperties, its properties’ historical performance, spot market prices and operations.other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. For the three and nine months ended September 30, 2022 and 2021, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
4. Inventory
Crude oil inventory includes oil in tank. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Crude oil inventory and equipment and materials are included in Inventory on the Company’s Condensed Consolidated Balance Sheets.
The minimum volume of product in a pipeline system that enables the system to operate is known as linefill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil linefill in third-party pipelines, which is included in Long-term inventory on the Company’s Condensed Consolidated Balance Sheets.
Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.
Total inventory consists of the following:
 September 30, 2017 December 31, 2016
 (In thousands)
Inventory   
Crude oil inventory$6,934
 $7,086
Equipment and materials10,235
 3,562
Total inventory$17,169
 $10,648
    
Long-term inventory   
Linefill in third-party pipelines$10,885
 $—
Long-term inventory$10,885
 $—
    
Total$28,054
 $10,648

5. Accounts Receivable, Net
The following table sets forth the Company’s accounts receivable, net:inventory:
September 30, 2022December 31, 2021
 (In thousands)
Inventory
Equipment and materials$19,932 $12,175 
Crude oil inventory41,024 16,781 
Total inventory60,956 28,956 
Long-term inventory
Linefill in third-party pipelines22,009 17,510 
Total long-term inventory22,009 17,510 
Total$82,965 $46,466 
5. Additional Balance Sheet Information
The following table sets forth certain balance sheet amounts comprised of the following:
September 30, 2022December 31, 2021
 (In thousands)
Accounts receivable, net
Trade accounts$563,287 $309,756 
Joint interest accounts118,845 40,890 
Other accounts41,879 28,270 
Total accounts receivable724,011 378,916 
Less: allowance for credit losses(6,862)(1,714)
Total accounts receivable, net$717,149 $377,202 
Accrued liabilities
Accrued capital costs$134,675 $33,085 
Accrued lease operating expenses81,812 29,478 
Accrued oil and gas marketing125,169 35,211 
Accrued general and administrative expenses34,907 13,270 
Accrued legal contingencies55,000 — 
Current portion of asset retirement obligations24,973 4,813 
Accrued dividends3,310 4,946 
Other accrued liabilities16,790 29,871 
Total accrued liabilities$476,636 $150,674 
11
 September 30, 2017 December 31, 2016
 (In thousands)
Accounts receivable, net   
Trade accounts$166,516
 $137,065
Joint interest accounts75,175
 40,322
Other accounts44,638
 28,257
Total286,329
 205,644
Allowance for doubtful accounts(946) (1,309)
Total accounts receivable, net$285,383
 $204,335
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6. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations (“ARO”) and proved oil and natural gas properties acquired in a business combination or upon impairment, at fair value on a non-recurring basis.
As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:
Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 — Pricing inputs are generally less observableunobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

Financial Assets and Liabilities
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The following tables set forth by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
 Fair value at September 30, 2017
 Level 1 Level 2 Level 3 Total
 (In thousands)
Assets:       
Money market funds$142
 $—
 $—
 $142
Commodity derivative instruments (see Note 7)—
 1,395
 —
 1,395
Total assets$142
 $1,395
 $—
 $1,537
Liabilities:       
Commodity derivative instruments (see Note 7)$—
 $20,115
 $—
 $20,115
Total liabilities$—
 $20,115
 $—
 $20,115
Fair value at September 30, 2022
Level 1Level 2Level 3Total
(In thousands)
Assets:
Commodity derivative contracts (see Note 7)$— $3,061 $— $3,061 
Contingent consideration (see Note 7)— 52,110 — 52,110 
Investment in unconsolidated affiliate (see Note 12)
138,452 — — 138,452 
Total assets$138,452 $55,171 $— $193,623 
Liabilities:
Commodity derivative contracts (see Note 7)(1)
$— $389,417 $15,086 $404,503 
Total liabilities$— $389,417 $15,086 $404,503 
 Fair value at December 31, 2016
 Level 1 Level 2 Level 3 Total
 (In thousands)
Assets:       
Money market funds$141
 $—
 $—
 $141
Commodity derivative instruments (see Note 7)—
 362
 —
 362
Total assets$141
 $362
 $—
 $503
Liabilities:       
Commodity derivative instruments (see Note 7)$—
 $72,183
 $—
 $72,183
Total liabilities$—
 $72,183
 $—
 $72,183
__________________ 
The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.
The Level 2 instruments presented in the tables above consist(1)     Includes $39.6 million of commodity derivative instruments, which includeliabilities paid in October 2022.
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 Fair value at December 31, 2021
 Level 1Level 2Level 3Total
 (In thousands)
Assets:
Commodity derivative contracts (see Note 7)$— $55 $— $55 
Contingent consideration (see Note 7)— 44,810 — 44,810 
Total assets$— $44,865 $— $44,865 
Liabilities:
Commodity derivative contracts (see Note 7)$— $204,729 $— $204,729 
Total liabilities$— $204,729 $— $204,729 
Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil, NGL and natural gas prices. The Company primarily utilizes fixed-price swaps, collars and collars.basis swaps to reduce the volatility of crude oil, NGL and natural gas prices on future expected production. The fair values of the Company’s commodity derivative instrumentsswaps, collars and basis swaps are based uponvalued by a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts, as there isbased on an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options.income approach. The significant inputs used are crude oilcommodity prices, volatility, skew, discount rate and the contract terms of the derivative instruments. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. The Company compares the valuation performed by the third-party preparer’s valuationpreparer to counterparty valuation statements investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves.assess the reasonableness of its valuation. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations,spread of the Company or similarly rated public issuers. The Company recorded an adjustment to reduce the fair value of its net derivative liability for these contracts by $0.5$12.1 million and $5.3 million at September 30, 20172022 and December 31, 2021, respectively. See Note 7—Derivative Instruments for additional information.
Transportation derivative contracts. The Company acquired two buy/sell transportation contracts in the Merger that are derivative contracts for which the Company has not elected the “normal purchase normal sale” exclusion under FASB ASC 815, Derivatives and Hedging (“ASC 815”). The Company recorded these contracts at fair value in its Condensed Consolidated Balance Sheet at the completion of the Merger on July 1, 2022, with additional adjustments to fair value recorded as of September 30, 2022. These transportation derivative contracts were valued based on an adjustmentincome approach, which considers various assumptions, including quoted forward prices for commodities, market differentials for crude oil and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of these contracts include certain market differential metrics that are unobservable during the term of the contracts. Such unobservable inputs are significant to reducethe contract valuation methodology, and the contracts’ fair values are therefore designated as Level 3 within the fair value hierarchy. See Note 7—Derivative Instruments for additional information.
Contingent consideration. Pursuant to the purchase and sale agreement entered into in connection with the Company’s divestiture of its net derivative liability by $2.0E&P assets in the Permian Basin in 2021, the Company is entitled to receive up to three earn-out payments of $25.0 million at December 31, 2016per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX West Texas Intermediate crude oil price index (“NYMEX WTI”) exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”).
There were no transfers between If NYMEX WTI for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter the buyer’s obligation to make any remaining earn-out payments is terminated. The fair value levels duringof the nine months endedPermian Basin Sale Contingent Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs include NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. See Note 7—Derivative Instruments for additional information.
Investment in unconsolidated affiliate. The Company elected the fair value option to account for its investment in Crestwood. The fair value of the Company’s investment in Crestwood was determined using Level 1 inputs based upon the quoted market price of Crestwood’s publicly traded common units at September 30, 20172022. As of the closing date of the OMP Merger (defined in Note 10—Divestitures) on February 1, 2022, fair value was determined using Level 2 inputs that included a discount to reflect a restriction on the Company's ability to sell the investment 90 days from the closing date. See Note 12—Investment in Unconsolidated Affiliate for additional information.
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Non-Financial Assets and 2016.Liabilities

The fair value of the Company’s non-financial assets and liabilities measured on a non-recurring basis are determined using valuation techniques that include Level 3 inputs.
Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments.
Whiting merger. On July 1, 2022, the Company completed the Merger with Whiting. The assets acquired and liabilities assumed were recorded at fair value as of July 1, 2022. The fair value of Whiting’s oil and gas properties was calculated using an income approach based on the net discounted future cash flows from the producing properties and related assets. The inputs utilized in the valuation of the oil and gas properties and related assets acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials), operating and development costs, expected future development plans for the properties and the utilization of a discount rate based on a market-based weighted-average cost of capital. The Company also recorded the asset retirement obligations assumed from Whiting at fair value. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of July 1, 2022, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. See Note 9—Acquisitions for additional information.
7. Derivative Instruments
Commodity derivative contracts. The Company utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices. The Company’s crude oil and natural gas contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oilWTI. NGL contracts settle monthly based on the average Mont Belvieu propane or Conway propane index price (“WTI”) andprices, as applicable. Natural gas contracts settle monthly based on the average NYMEX Henry Hub natural gas index price (“Henry Hub”NYMEX HH”), respectively. At September 30, 2017,while natural gas basis swaps settle monthly based on the average fixed differential between NYMEX HH and the Northern Natural Gas Ventura (“NNG Ventura”) index price.
The Company utilizedprimarily utilizes fixed-price swaps, collars and two-way and three-way costless collar optionsbasis swaps to reduce the volatility of crude oil, NGL and natural gas prices on a significant portion of its future expected oil and natural gas production. A swap isSwaps are designed to establish a sold callfixed-price for the volumes under contract, while collars are designed to establish a minimum price (floor) and a purchased put established at the samemaximum price (both ceiling and floor), which the Company will receive(ceiling) for the volumes under contract. A two-way collar isThe Company’s basis swaps are designed to establish a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor)fixed differential between NYMEX and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plusreferenced in the difference betweencontract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the purchased put andterms of current contracts in order to improve the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract.pricing parameters in existing contracts.
All derivative instruments are recorded on the Company’s Condensed Consolidated Balance Sheets as either assets or liabilities measured at fair value (see Note 6 – 6—Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge,The Company records the changes in fair value are recognized in the other income (expense) section of the Company’s Condensed Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actualDerivative settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s commodity derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlementscontracts are reflected as investing activities inon the Company’s Condensed Consolidated Statements of Cash Flows.Flows and represent net cash payments to or receipts from counterparties upon the maturity of a derivative contract.

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In connection with the completion of the Merger, the following outstanding commodity derivative contracts were novated to the Company on July 1, 2022:
CommoditySettlement
Period		Derivative
Instrument		VolumesWeighted Average Prices
Fixed-Price SwapsFloorCeiling
  
Crude oil2022Fixed-price swaps1,840,000 Bbl$76.92 
Crude oil2022Two-way collar5,628,000 Bbl$47.20 $57.33 
Crude oil2023Fixed-price swaps1,172,000 Bbl$76.79 
Crude oil2023Two-way collar3,443,500 Bbl$46.75 $58.87 
Natural gas2022Fixed-price swaps4,140,000 MMBtu$3.97 
Natural gas2022Two-way collar10,074,000 MMBtu$2.68 $3.31 
Natural gas2023Fixed-price swaps1,800,000 MMBtu$4.25 
Natural gas2023Two-way collar8,799,000 MMBtu$2.85 $3.57 
Natural gas basis(1)
2022Fixed-price swaps620,000 MMBtu$1.17 
Natural gas basis(1)
2023Fixed-price swaps5,920,000 MMBtu$0.40 
NGL - Propane(2)
2022Fixed-price swaps7,728,000 Gallons$1.07 
NGL - Propane(3)
2022Fixed-price swaps30,912,000 Gallons$1.04 
NGL - Propane(3)
2023Fixed-price swaps7,560,000 Gallons$1.16 

At September 30, 2017,2022, the Company had the following outstanding commodity derivative instruments:contracts:
CommoditySettlement
Period		Derivative
Instrument		VolumesWeighted Average Prices
Fixed-Price SwapsFloorCeiling
  
Crude oil2022Two-way collar3,864,000 Bbl$48.13 $60.00 
Crude oil2022Fixed-price swaps2,760,000 Bbl$72.32 
Crude oil2023Two-way collar7,823,500 Bbl$45.77 $62.25 
Crude oil2023Fixed-price swaps6,282,000 Bbl$55.00 
Natural gas2022Two-way collar4,370,000 MMBtu$2.71 $3.41 
Natural gas2022Fixed-price swaps2,760,000 MMBtu$4.19 
Natural gas2023Two-way collar8,799,000 MMBtu$2.84 $3.57 
Natural gas2023Fixed-price swaps1,800,000 MMBtu$4.25 
Natural gas basis(1)
2022Fixed-price swaps620,000 MMBtu$1.17 
Natural gas basis(1)
2023Fixed-price swaps5,920,000 MMBtu$0.40 
NGL - Propane(2)
2022Fixed-price swaps3,864,000 Gallons$1.07 
NGL - Propane(3)
2022Fixed-price swaps15,456,000 Gallons$1.04 
NGL - Propane(3)
2023Fixed-price swaps7,560,000 Gallons$1.16 
__________________ 
(1)    The weighted average price associated with the natural gas basis swaps shown in the tables above represents the average fixed differential to NYMEX HH as stated in the related contracts, which is compared to the NNG Ventura index price for each period. If NYMEX HH combined with the fixed differential as stated in each contract is higher than the NNG Ventura index price at any settlement date, the Company receives the difference. Conversely, if the NNG Ventura index price is higher than NYMEX HH combined with the fixed differential, the Company pays the difference.
(2)    Settled based on the Mont Belvieu propane price.
(3)    Settled based on the Conway propane price.
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Commodity
Settlement
Period
Derivative
Instrument
Volumes
Weighted Average Prices
Fair Value
Asset (Liability)




Swap
Sub-Floor
Floor
Ceiling


 
 





(In thousands)
Crude oil
2017
Swaps
2,428,000
 Bbl
$49.98
      
$(3,220)
Crude oil
2017
Two-way collar
728,000
 Bbl
    $46.25
 $54.37

(576)
Crude oil
2017
Three-way collar
546,000
 Bbl
  $31.67
 $45.83
 $59.94

42
Crude oil
2018
Swaps
12,951,000
 Bbl
$50.81
      
(13,746)
Crude oil
2018
Two-way collar
1,250,000
 Bbl
    $48.19
 $53.33

(927)
Crude oil
2018
Three-way collar
186,000
 Bbl
  $31.67
 $45.83
 $59.94

51
Crude oil
2019
Swaps
3,423,000
 Bbl
$50.83
      
(846)
Crude oil
2019
Two-way collar
93,000
 Bbl
    $48.67
 $53.07

(25)
Crude oil 2020 Swaps 217,000
 Bbl $50.82
       28
Natural gas 2017 Swaps 2,024,000
 Mmbtu $3.30
       502
Natural gas 2018 Swaps 6,205,000
 Mmbtu $3.05
       (3)












 
 

$(18,720)
Transportation derivative contracts. The Company acquired two contracts in the Merger that provide for the transportation of crude oil through a buy/sell structure from North Dakota to either Cushing, Oklahoma or Guernsey, Wyoming. The contracts require the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreements. At July 1, 2022, upon the closing of the Merger, the Company determined that these contracts qualified as derivatives and did not elect the “normal purchase normal sale” exclusion. The fair value of these transportation derivative contracts as of July 1, 2022 was estimated to be a liability of $22.0 million. As of September 30, 2022, the estimated fair value of these contracts was $15.1 million, of which $10.4 million was classified as a current derivative liability and $4.7 million was classified as a non-current derivative liability on the Condensed Consolidated Balance Sheet (see Note 6—Fair Value Measurements). The Company records the changes in fair value of these contracts to gathering, processing and transportation expenses on the Company’s Condensed Consolidated Statements of Operations. Settlements on these contracts are reflected as operating activities on the Company’s Condensed Consolidated Statements of Cash Flows and represent cash payments to the counterparties for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable.
Contingent consideration. The Company bifurcated the Permian Basin Sale Contingent Consideration from the host contract and accounted for it separately at fair value. The fair value of the Permian Basin Sale Contingent Consideration was estimated to be $32.9 million as of the close date of the Permian Basin Sale (defined in Note 10—Divestitures). The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Condensed Consolidated Statements of Operations as a net gain or loss on derivative instruments. As of September 30, 2022, the estimated fair value of the Permian Basin Sale Contingent Consideration was $52.1 million and was classified as a non-current derivative asset on the Condensed Consolidated Balance Sheet. See Note 6—Fair Value Measurements and Note 10—Divestitures for additional information.
The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Condensed Consolidated Statements of Operations for the periods presented:
Three Months Ended September 30,Nine Months Ended September 30,
Derivative InstrumentStatements of Operations Location2022202120222021
 (In thousands)
Commodity price hedges (commodity derivative contracts)Net gain (loss) on derivative instruments$344,379 $(108,647)$(136,066)$(557,199)
Buy/sell transportation contracts (commodity derivative contracts)
Gathering, processing and transportation expenses(1)
6,939 — 6,939 — 
Embedded commodity derivative (contingent consideration)Net gain (loss) on derivative instruments(6,970)6,857 7,300 6,857 
Embedded commodity derivative (contingent consideration)Gain on sale of assets— — — 32,860 
  Three Months Ended September 30, Nine Months Ended September 30,
Statement of Operations Location 2017 2016 2017 2016
  (In thousands)
Net gain (loss) on derivative instruments $(54,310) $20,847
 $52,297
 $(55,624)
__________________ 

(1)    The change in the fair value of the transportation derivative contracts was recorded as a gain in gathering, processing and transportation expenses for the three and nine months ended September 30, 2022.

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Condensed Consolidated Balance Sheets.
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The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheets:
September 30, 2022
Derivative InstrumentBalance Sheet LocationGross AmountGross Amount OffsetNet Amount
(In thousands)
Derivatives assets:
Commodity derivativesDerivative instruments — current assets$28,137 $(25,076)$3,061 
Commodity derivativesDerivative instruments — non-current assets4,324 (4,324)— 
Contingent considerationDerivative instruments — non-current assets52,110 — 52,110 
Total derivatives assets$84,571 $(29,400)$55,171 
Derivatives liabilities:
Commodity derivatives(1)
Derivative instruments — current liabilities$381,318 $(25,076)$356,242 
Commodity derivatives (buy/sell transportation contracts)Derivative instruments — current liabilities10,363 — 10,363 
Commodity derivativesDerivative instruments — non-current liabilities37,499 (4,324)33,175 
Commodity derivatives (buy/sell transportation contracts)Derivative instruments — non-current liabilities4,723 — 4,723 
Total derivatives liabilities$433,903 $(29,400)$404,503 
December 31, 2021
Derivative InstrumentBalance Sheet LocationGross AmountGross Amount OffsetNet Amount
(In thousands)
Derivatives assets:
Commodity derivativesDerivative instruments — non-current assets$55 $— $55 
Contingent considerationDerivative instruments — non-current assets44,810 — 44,810 
Total derivatives assets$44,865 $— $44,865 
Derivatives liabilities:
Commodity derivativesDerivative instruments — current liabilities$96,172 $(6,725)$89,447 
Commodity derivativesDerivative instruments — non-current liabilities133,655 (18,373)115,282 
Total derivatives liabilities$229,827 $(25,098)$204,729 
__________________ 
(1)     Includes $39.6 million of commodity derivative liabilities paid in October 2022.
17
    September 30, 2017
Commodity Balance Sheet Location Gross Recognized Assets/Liabilities Gross Amount Offset Net Recognized Fair Value Assets/Liabilities
    (In thousands)
Derivatives assets:        
Commodity contracts Derivative instruments — current assets $971
 $(279) $692
Commodity contracts Derivative instruments — non-current assets 2,197
 (1,494) 703
Total derivatives assets $3,168
 $(1,773) $1,395
Derivatives liabilities:        
Commodity contracts Derivative instruments — current liabilities $24,590
 $(8,178) $16,412
Commodity contracts Derivative instruments — non-current liabilities 5,284
 (1,581) 3,703
Total derivatives liabilities $29,874
 $(9,759) $20,115
         
    December 31, 2016
Commodity Balance Sheet Location Gross Recognized Asset/Liabilities Gross Amount Offset Net Recognized Fair Value Asset/Liabilities
    (In thousands)
Derivatives assets:        
Commodity contracts Derivative instruments — current assets $482
 $(120) $362
Total derivatives assets $482
 $(120) $362
Derivatives liabilities:        
Commodity contracts Derivative instruments — current liabilities $66,838
 $(6,369) $60,469
Commodity contracts Derivative instruments — non-current liabilities 14,164
 (2,450) 11,714
Total derivatives liabilities $81,002
 $(8,819) $72,183
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8. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
September 30, 2022December 31, 2021
 (In thousands)
Proved oil and gas properties$4,880,250 $1,393,836 
Less: Accumulated depreciation, depletion and amortization(326,209)(107,277)
Proved oil and gas properties, net4,554,041 1,286,559 
Unproved oil and gas properties46,028 2,001 
Other property and equipment75,434 48,981 
Less: Accumulated depreciation(19,439)(17,109)
Other property and equipment, net55,995 31,872 
Total property, plant and equipment, net$4,656,064 $1,320,432 
 September 30, 2017 December 31, 2016
 (In thousands)
Proved oil and gas properties(1)
$6,828,758
 $6,476,833
Less: accumulated depreciation, depletion, amortization and impairment(2,258,203) (1,886,732)
Proved oil and gas properties, net4,570,555
 4,590,101
Unproved oil and gas properties812,027
 819,735
Other property and equipment783,542
 618,790
Less: accumulated depreciation(130,506) (109,059)
Other property and equipment, net653,036
 509,731
Total property, plant and equipment, net$6,035,618
 $5,919,567
9. Acquisitions
__________________
2022 Acquisitions
Whiting merger. On July 1, 2022, the Company completed the Merger with Whiting and issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting shareholders. Also on July 1, 2022 and pursuant to the Merger Agreement, the Company (i) assumed the outstanding Whiting Series A Warrants and Whiting Series B Warrants, (ii) assumed the outstanding Whiting equity-based compensation awards and (iii) paid cash to satisfy and discharge in full the Whiting credit facility.
Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the Merger at their estimated fair value on July 1, 2022 of $2.8 billion. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of Whiting requires judgement and certain assumptions to be made. See Note 6—Fair Value Measurements for additional information.
The tables below present the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on July 1, 2022.
(1)Included in the Company’s proved oilPurchase Price Consideration
(In thousands)
Common stock issued to Whiting shareholders(1)
$2,478,036 
Cash paid to Whiting shareholders(1)
245,436 
Replacement of Whiting Series A Warrants and Whiting Series B Warrants(2)
79,774 
Replacement of Whiting equity-based compensation awards(3)
27,402 
Cash paid to settle Whiting credit facility(4)
2,154 
Total consideration transferred$2,832,802 
__________________ 
(1)     The Company issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting shareholders as Merger Consideration. Each holder of Whiting common stock received 0.5774 shares of common stock as Share Consideration and $6.25 of cash as Cash Consideration. The fair value of the common stock issued was based on the closing price of the Company’s common stock on July 1, 2022 of $109.30. See Note 17—Stockholder's Equity for additional information.
(2)    The Company assumed (i) 4,833,455 Whiting Series A Warrants and (ii) 2,418,832 Whiting Series B Warrants. The replacement of Whiting Series A and B Warrants was based on the closing price of the warrants on July 1, 2022 of $11.25 and $10.50, respectively. See Note 17—Stockholder's Equity for additional information.
(3)    The Whiting equity awards were replaced with awards issued by Chord with similar terms and conditions as the original awards. The fair value of the replacement equity awards attributable to pre-Merger service was recorded as consideration transferred. See Note 16— Equity-Based Compensation for additional information.
(4)    On July 1, 2022, the Company fully satisfied all obligations under the Whiting credit facility and the Whiting credit facility was concurrently terminated. See Note 13—Long-Term Debt for additional information.

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Purchase Price Allocation
(In thousands)
Assets acquired:
Cash and cash equivalents$94,641 
Accounts receivable, net329,331 
Inventory35,256 
Prepaid expenses14,851 
Other current assets428 
Current assets held for sale16,074 
Oil and gas properties are estimates of future asset3,192,564 
Other property and equipment31,244 
Long-term inventory3,138 
Operating right-of-use assets15,752 
Deferred tax assets250,170 
Other assets3,346 
Total assets acquired$3,986,795 
Liabilities assumed:
Accounts payable$116,769 
Revenues and production taxes payable249,370 
Accrued liabilities215,218 
Derivatives instruments (current liability)471,693 
Current operating lease liabilities2,629 
Other current liabilities727 
Current liabilities held for sale9,410 
Asset retirement costs of $44.0 millionobligations57,197 
Derivative instruments (long-term liability)15,128 
Operating lease liabilities13,123 
Other liabilities2,729 
Total liabilities assumed$1,153,993 
Net assets acquired$2,832,802 

Post-merger operating results. The results of operations of Whiting have been included in the Company’s unaudited condensed consolidated financial statements since the closing of the Merger on July 1, 2022. The following table summarizes the total revenues and income from continuing operations before income taxes attributable to Whiting that were recorded in the Company’s Condensed Consolidated Statement of Operations for the periods presented.
Three and $42.9 million atNine Months Ended September 30, 2017 and December 31, 2016, respectively.2022
(In thousands)
Revenues$562,089 
Income from continuing operations before income taxes299,118 
Midstream assets acquisition.
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Unaudited pro forma financial information. Summarized below are the condensed consolidated results of operations for the periods presented, on an unaudited pro forma basis, as if the Merger had occurred on January 1, 2021. The information presented below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the Merger, including transaction costs incurred by the Company and Whiting. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Merger occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results. The pro forma results of operations do not include any future cost savings or other synergies that may result from the Merger or any estimated costs that have not yet been incurred by the Company to integrate the Whiting assets.
Three Months Ended September 30,Nine Months Ended September 30,
202120222021
(In thousands)
Revenues$803,076 $3,739,261 $2,210,632 
Net income attributable to Chord224,262 1,701,478 21,525 
Net income attributable to Chord per share:
Basic$5.26 $40.53 $0.50 
Diluted5.13 38.92 0.50 
Other information. The Company recorded an assumed liability of $18.0 million in accrued liabilities on the Condensed Consolidated Balance Sheet as of July 1, 2022 related to success-based transaction costs that were incurred by Whiting prior to the consummation of the Merger. These amounts were paid during the three months ended September 30, 2022.
In addition, the Company recorded an assumed liability of $55.0 million in accrued liabilities on the Condensed Consolidated Balance Sheet as of July 1, 2022 related to a loss contingency from a legal proceeding with Arguello Inc. and Freeport-McMoran Oil & Gas LLC that the Company determined was both probable and reasonably estimable under FASB ASC 450-20, Loss Contingencies as of the consummation of the Merger. See Note 19 — Commitments and Contingencies for additional information.
2021 Acquisitions
Williston Basin Acquisition. On April 25, 2017,October 21, 2021, the Company completed purchase and sale agreements with two undisclosed private sellers to acquire certain midstream assetsthe acquisition of approximately 95,000 net acres in McKenzie County, North Dakotathe Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy Inc., for total cash consideration of $12.7$585.8 million which includes $4.9(the “Williston Basin Acquisition”). The Company paid a deposit to QEP of $74.5 million of installment notes payable. Based on May 3, 2021 and $511.3 million at closing on October 21, 2021. The Company funded the FASB’s authoritative guidance,Williston Basin Acquisition with cash on hand, including proceeds from the Permian Basin Sale (defined in Note 10—Divestitures) and the Senior Notes (defined in Note 13—Long-Term Debt).
The Williston Basin Acquisition was accounted for as an asset acquisition qualified as a business combination, and as such, the Company estimatedunder ASC 805, since substantially all of the fair value of the assets acquired related to proved oil and gas properties. The Company applied the cost accumulation model under ASC 805, and as such, recognized the assets acquired in the Williston Basin Acquisition at cost, including transaction costs, on a relative fair value basis. There were no material deferred income taxes from the Williston Basin Acquisition, as the tax basis of the acquisition date.assets acquired and liabilities assumed was equal to the book basis at closing.
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10. Divestitures
2022 Divestitures
OMP divestiture. In October 2021, OMP, a master limited partnership formed by the Company to own, develop, operate and acquire midstream assets in North America, and OMP GP LLC (“OMP GP”), the general partner of OMP, entered into an Agreement and Plan of Merger (the “OMP Merger Agreement”) with Crestwood and Crestwood GP. Pursuant to the OMP Merger Agreement, the Company agreed to merge OMP into a subsidiary of Crestwood and exchange all of its OMP common units and all of the limited liability company interests of OMP GP for $160.0 million in cash and 20,985,668 common units of Crestwood (the “OMP Merger”). The OMP Merger represented a strategic shift for the Company and qualified for reporting as a discontinued operation under ASC 205-20. See Note 11—Discontinued Operations for additional information.
On February 1, 2022, the Company completed the OMP Merger and received $160.0 million in cash and 20,985,668 common units of Crestwood. Immediately prior to the completion of the OMP Merger, the Company owned approximately 70% of OMP’s issued and outstanding common units. The Company recorded a pre-tax gain on sale of assets of $518.9 million, which included (i) the assets acquired at their estimatedcash consideration of $160.0 million, (ii) the fair value of $12.7 million, which the Company considers to be representativeCompany’s retained investment in Crestwood of $568.3 million; less (iii) the book value of the price paid by a typical market participant. This measurement resultedCompany’s investment in no goodwill or bargain purchase being recognized.
OMP of $198.0 million and (iv) transaction costs of $11.4 million. The resultsgain on sale of assets was reported within income (loss) from discontinued operations for the acquisition have been included in the Company’s condensed consolidated financial statements since the closing date. Pro forma information is not presented as the pro forma results would not be materially different from the information presented inattributable to Chord, net of income tax on the Company’s Condensed Consolidated Statement of Operations for the nine months ended September 30, 2022. See Note 6—Fair Value Measurements and Note 12—Investment in Unconsolidated Affiliate for additional information.
In connection with the closing of the OMP Merger, certain contracts were assigned to Crestwood for midstream services and the Company has continuing cash outflows to Crestwood for these services. The Company has determined that Crestwood is a related party. See Note 12—Investment in Unconsolidated Affiliate for additional information.
Rio Blanco County Divestiture. On July 14, 2022, the Company completed the divestiture of its interests in various assets, including producing wells and an equity interest in a pipeline in Rio Blanco County, Colorado, for an aggregate sales price of $8.0 million (before final closing adjustments) (the “Rio Blanco County Divestiture”). No gain or loss was recognized for this sale. The net assets from the Rio Blanco County Divestiture were measured at fair value and classified as held-for-sale upon consummation of the Merger on July 1, 2022.
2021 Divestitures
Well services. On March 22, 2021, the Company completed the sale of certain well services equipment and inventory in connection with its 2020 exit from the well services business for total consideration of $5.5 million, comprised of cash proceeds of $2.6 million and a $2.9 million promissory note. As of September 30, 2022, the interest rate on the promissory note was 11.6% and the remaining principal balance was $0.5 million.
Midstream Simplification. On March 30, 2021, the Company contributed to OMP its remaining 64.7% limited liability company interest in Bobcat DevCo LLC and 30.0% limited liability company interest in Beartooth DevCo LLC, as well as eliminated OMP’s incentive distribution rights, in exchange for a cash distribution of $231.5 million and 12,949,644 common units in OMP (the “Midstream Simplification”). The Midstream Simplification was accounted for as a transaction between entities under common control.
Permian Basin Sale. On May 20, 2021, Oasis Petroleum Permian LLC (“OP Permian”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement (the “Permian Basin Sale PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”). Pursuant to the Permian Basin Sale PSA, OP Permian agreed to sell to Percussion its remaining upstream assets in the Texas region of the Permian Basin with an effective date of March 1, 2021, for an aggregate purchase price of $450.0 million (the “Permian Basin Sale”). The aggregate purchase price consisted of $375.0 million in cash at closing and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025. See Note 6—Fair Value Measurements for additional information on the earn-out payments. The Company completed the Permian Basin Sale on June 29, 2021 and received cash proceeds of $342.3 million.
In addition, the Company divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 and received cash proceeds of $30.0 million.
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11. Discontinued Operations
The OMP Merger represented a strategic shift for the Company and qualified as a discontinued operation in accordance with ASC 205-20.
Condensed Consolidated Statements of Operations
The results of operations reported as discontinued operations in connection with the OMP Merger were as follows for the periods presented (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2022202120222021
Revenues
Oil and gas revenues$— $162 $— $865 
Purchased oil and gas sales(1)
— (33,812)(13,364)(92,464)
Midstream revenues— 66,712 23,271 183,807 
Total revenues— 33,062 9,907 92,208 
Operating expenses
Lease operating expenses(1)
— (15,582)(4,535)(47,485)
Midstream expenses— 32,396 13,224 83,841 
Gathering, processing and transportation expenses(1)
— (13,628)(3,555)(38,324)
Purchased oil and gas expenses(1)
— (31,948)(12,506)(88,044)
Depreciation, depletion and amortization— 9,648 — 28,605 
Impairment— — — 2 
General and administrative expenses(1)
— (574)3,314 (1,039)
Total operating expenses— (19,688)(4,058)(62,444)
Gain on sale of assets— — 518,900 — 
Operating income— 52,750 532,865 154,652 
Other income (expense)
Interest expense, net of capitalized interest— (10,997)(3,685)(25,977)
Other expense— (176)(93)(64)
Total other expense— (11,173)(3,778)(26,041)
Income from discontinued operations before income taxes— 41,577 529,087 128,611 
Income tax expense(2)
(59,858)— (101,080)— 
Income (loss) from discontinued operations, net of income tax(59,858)41,577 428,007 128,611 
Net income attributable to non-controlling interests— 11,382 2,311 27,654 
Income (loss) from discontinued operations attributable to Chord, net of income tax$(59,858)$30,195 $425,696 $100,957 
__________________ 
(1)Includes discontinued intercompany eliminations.
(2)The Company applied the intraperiod tax allocation rules in accordance with FASB ASC 740-20, Intraperiod Tax Allocation (“ASC 740-20”) to determine the allocation of tax expense between continuing operations and discontinued operations. ASC 740-20 generally requires the allocation of tax expense to be based on a comparative calculation of tax expense with and without income from discontinued operations. Prior to the release of a portion of the Company’s valuation allowance in the third quarter of 2022 (see Note 15—Income Taxes for additional information), the Company recorded $41.2 million of income tax expense attributable to discontinued operations during the six months ended June 30, 2022. During the three months ended September 30, 2022, the Company released a portion of its valuation allowance and allocated the majority of the income tax benefit associated with the release of the valuation allowance to continuing operations. The total tax expense associated with the OMP Merger was partially offset by the release of the valuation allowance allocated to discontinued operations, resulting in an incremental tax expense of $59.9 million recorded in the three months ended September 30, 2022, since a smaller portion of the deferred tax liabilities reported in discontinued operations is being offset with deferred tax assets.
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Condensed Consolidated Balance Sheet
The carrying amounts of the major classes of assets and liabilities related to the OMP Merger were as follows for the period presented (in thousands):
December 31, 2021
ASSETS
Current assets
Cash and cash equivalents$2,669 
Accounts receivable, net6,509 
Inventory8,541 
Prepaid expenses456 
Total current assets of discontinued operations18,175 
Property, plant and equipment
Oil and gas properties (successful efforts method)(1)
(3,207)
Other property and equipment933,667 
Less: accumulated depreciation, depletion and amortization(32,102)
Total property, plant and equipment, net898,358 
Operating right-of-use assets671 
Intangible assets40,277 
Goodwill70,534 
Other assets1,303 
Total non-current assets of discontinued operations1,011,143 
Total assets of discontinued operations$1,029,318 
LIABILITIES
Current liabilities
Accounts payable$43 
Revenues and production taxes payable1,635 
Accrued liabilities36,183 
Accrued interest payable9,296 
Current operating lease liabilities733 
Other current liabilities564 
Total current liabilities of discontinued operations48,454 
Long-term debt644,078 
Asset retirement obligations904 
Other liabilities6,217 
Total non-current liabilities of discontinued operations651,199 
Total liabilities of discontinued operations$699,653 
___________________________
(1) Includes discontinued intercompany eliminations.    
Condensed Consolidated Statements of Cash Flows
There was no depreciation, depletion and amortization attributable to discontinued operations in “Cash flows from operating activities” for the nine months ended September 30, 2022. For the nine months ended September 30, 2021, depreciation, depletion and amortization attributable to discontinued operations in “Cash flows from operating activities” was $28.6 million. Capital expenditures attributable to discontinued operations included in “Cash flows used in investing activities” were $6.1 million for the nine months ended September 30, 2022 and $20.8 million for the nine months ended September 30, 2021. There were no significant non-cash activities from discontinued operations for the periods presented.
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12. Investment in Unconsolidated Affiliate
On February 1, 2022, the Company completed the OMP Merger and received 20,985,668 Crestwood common units. On September 12, 2022, the Company sold an aggregate of 16,000,000 common units in separate transactions and received net proceeds of $428.2 million. The Company recorded a gain on sale of $43.0 million which was recognized under net gain from investment in unconsolidated affiliate on the Condensed Consolidated Statements of Operations. The Company owns 4,985,668 common units of Crestwood, representing less than 5% of Crestwood’s issued and outstanding common units. The carrying amount of the Company’s investment in Crestwood is recorded to investment in unconsolidated affiliate on the Condensed Consolidated Balance Sheet. The fair value of the Company’s investment in Crestwood was $138.5 million as of September 30, 2022.
During the three and nine months ended September 30, 2022, the Company recorded an unrealized gain for the change in the fair value of its investment in Crestwood of $18.4 million and an unrealized loss of $44.6 million, respectively, and a realized gain for a cash distribution from Crestwood of $13.7 million and $40.6 million, respectively. The Company records changes in the fair value of its investment in Crestwood and cash distributions received from Crestwood to net gain from investment in unconsolidated affiliate on the Condensed Consolidated Statements of Operations.
The Company initially appointed two directors to the Board of Directors of Crestwood GP pursuant to a director nomination agreement executed in connection with the consummation of the OMP Merger. On September 15, 2022, in connection with the completion of the sale of Crestwood common units and pursuant to the terms of the previously executed director nomination agreement, both directors resigned from the Board of Directors of Crestwood GP. As a result of the Company’s sale of Crestwood common units and the subsequent resignation of two directors from the Board of Directors of Crestwood GP, the Company does not have the ability to exercise significant influence over Crestwood as of September 30, 2022.
9.Related Party Transactions
The Company has determined that Crestwood is a related party due to its ownership of Crestwood common units.
The following table presents the revenues, lease operating expenses and gathering, processing and transportation expenses (on a net basis) with Crestwood for the periods presented:
Three Months Ended September 30, 2022Nine Months Ended September 30, 2022
(In thousands)
Revenues$11,286 $11,286 
Lease operating expenses19,041 51,116 
Gathering, processing and transportation expenses17,812 40,719 
As of September 30, 2022, amounts due from Crestwood were $7.8 million and amounts due to Crestwood were $66.6 million.
13. Long-Term Debt
The Company’s long-term debt consists of the following:
September 30, 2022December 31, 2021
 (In thousands)
Senior secured revolving line of credit$— $— 
Senior unsecured notes400,000 400,000 
Less: unamortized deferred financing costs(6,218)(7,476)
Total long-term debt, net$393,782 $392,524 
 September 30, 2017 December 31, 2016
 (In thousands)
Senior secured revolving line of credit$395,000
 $363,000
OMP revolving line of credit—
 —
Senior unsecured notes   
7.25% senior unsecured notes due February 1, 201954,275
 54,275
6.5% senior unsecured notes due November 1, 2021395,501
 395,501
6.875% senior unsecured notes due March 15, 2022937,080
 937,080
6.875% senior unsecured notes due January 15, 2023366,094
 366,094
2.625% senior unsecured convertible notes due September 15, 2023300,000
 300,000
Total principal of senior unsecured notes2,052,950
 2,052,950
Less: unamortized deferred financing costs on senior unsecured notes(24,295) (28,268)
Less: unamortized debt discount on senior unsecured convertible notes(83,042) (90,468)
Total long-term debt$2,340,613
 $2,297,214
The carrying amount of the Company’s long-term debt reported in the Condensed Consolidated Balance Sheet at September 30, 2017 was $2,340.6 million, which included $2,053.0 million of senior unsecured notes, a reduction for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and a reduction for the unamortized deferred financing costs on the senior unsecured notes of $83.0 million and $24.3 million, respectively, and $395.0 million of borrowings under the senior secured revolving line of credit (the “Oasis Credit Facility”). The Company’s revolving credit facility is recorded at a value that approximates its fair value since its variable interest rate is tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $2,109.1 million at September 30, 2017.

Senior secured revolving line of credit.The Company has a senior secured revolving credit facility (the “Credit Facility”) among Chord, as parent, Oasis Petroleum North America LLC, a wholly-owned subsidiary of the Oasis Credit Facility of $2,500.0 millionCompany, as of September 30, 2017, which has a maturity date of April 13, 2020, provided that the 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”borrower, and Wells Fargo Bank, N.A. (“Wells Fargo”), of which $54.3 million is outstanding, are retired or refinanced 90 days prior to their maturity. The Oasis Credit Facility is restricted to a borrowing base, which is reserve-basedas administrative agent and subject to semi-annual redeterminations on April 1 and October 1 of each year. On April 10, 2017, the lenders under the Oasis Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for Aprilparty thereto.
On July 1, 2017, resulting in an increase in the borrowing base from $1,150.0 million to $1,600.0 million; however, the Company elected to limit the Lenders’ aggregate commitment to $1,150.0 million. On September 25, 2017,2022, the Company entered into the ninth amendmentAmended and Restated Credit Agreement to, among other things; (i) increase the aggregate maximum credit amount to $3.0 billion, (ii) increase the borrowing base to $2.0 billion, (iii) increase the aggregate amount of elected commitments to $800.0 million, (iv) extend the maturity date to July 1, 2027, (v) reduce the margin on outstanding borrowings by 125 basis points and (vi) increase the consolidated total leverage ratio financial covenant to 3.50x. Borrowings are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the Oasis Credit Facilityborrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR
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Loan (each as defined in the amended and restated credit agreement). The Company incurs interest on outstanding Term SOFR Loans or ABR Loans at their respective interest rate plus the margin shown in the table below plus a 0.1% credit spread adjustment applicable to permitTerm SOFR Loans. In addition, the transactions and agreements entered intounused borrowing base is subject to a commitment fee as shown in connection with the OMP IPO.table below:
Total Commitment Utilization PercentageABR LoansSOFR LoansCommitment Fee
Less than 25%0.75 %1.75 %0.375 %
Greater than or equal to 25% but less than 50%1.00 %2.00 %0.375 %
Greater than or equal to 50% but less than 75%1.25 %2.25 %0.500 %
Greater than or equal to 75% but less than 90%1.50 %2.50 %0.500 %
Greater than or equal to 90%1.75 %2.75 %0.500 %
At September 30, 2017,2022, the Company had $395.0 million of LIBOR loans at a weighted average interest rate of 3.0%no borrowings outstanding and $10.0$5.9 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $745.0$794.1 million. On a quarterly basis,At December 31, 2021, the Company also pays a 0.375% (ashad no borrowings outstanding and $2.4 million of outstanding letters of credit under the Credit Facility, resulting in an unused borrowing capacity of $447.6 million. As of September 30, 2017) annualized commitment fee on2022, the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
The Company was in compliance with the financial covenants under the Credit Facility.
For the three and nine months ended September 30, 2022, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.57%. For the nine months ended September 30, 2021, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.20%. The fair value of the Oasis Credit Facility as of September 30, 2017.
OMP Operating LLC revolving line of credit. On September 25, 2017, OMP entered into a credit agreement (the “OMP Credit Agreement”) for a $200.0 million revolving credit facility with OMP Operating LLC, a subsidiary of OMP (see Note 3 – Oasis Midstream Partners LP), as borrower (the “OMP Credit Facility”), which has a maturity date of September 25, 2022. The OMP Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. The borrowing capacity on the OMP Credit Facility may be increased up to $400.0 million, subject to certain conditions. No amounts were outstandingapproximates its carrying value since borrowings under the OMP Credit Facility at September 30, 2017.
Borrowings under the OMP Credit Facility bear interest at a rate per annum equalvariable rates, which are tied to current market rates.
On October 31, 2022, the applicable margin (as described below) plus (i) with respectCompany completed its semi-annual borrowing base redetermination and entered into its Second Amendment to Eurodollar Loans,Amended and Restated Credit Agreement to increase the Adjusted LIBO Rate (as defined inaggregate amount of elected commitments to $1.0 billion and increase the OMP Credit Agreement) or (ii) with respectborrowing base to ABR Loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Agreement). The applicable margin for borrowings under the OMP Credit Facility varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75%, and (b) in the case of ABR Loans or swingline loans, 0.75% to 1.75%. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%.$2.75 billion.
The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio, (2) consolidated secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Facility). All obligations of OMP Operating LLC, as the borrower under the OMP Credit Facility, are guaranteed by OMP and all wholly-owned material subsidiaries of OMP. OMP Operating LLC was in compliance with the financial covenants of the OMP Credit Facility at September 30, 2017.
Senior unsecured notes. At September 30, 2017,2022, the Company had $1,753.0$400.0 million principal amount of 6.375% senior unsecured notes outstanding with maturities ranging from February 2019 to January 2023 and coupons ranging from 6.50% to 7.25%due June 1, 2026 (the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all ofInterest on the Senior Notes for cash at certain redemption prices equal to a certain percentageis payable semi-annually on June 1 and December 1 of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par plus accrued and unpaid interest to the redemption date.

Senior unsecured convertible notes. In September 2016, the Company issued $300.0 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of September 30, 2017, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.
Upon issuance, the Company separately accounted for the liability and equity components of the Senior Convertible Notes in accordance with Accounting Standards Codification 470-20. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Senior Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 8.97% per annum.year. The fair value of the Senior Convertible Notes, aswhich are publicly traded among qualified institutional investors and represent a Level 1 fair value measurement, was $380.0 million at September 30, 2022.
Whiting credit facility. Upon consummation of the issuance dateMerger on July 1, 2022, the Whiting credit facility was estimated at $206.8 million, resulting in a debt discount at inception of $93.2 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Senior Convertible Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital and will not be remeasured as long as it continues to meet the conditions for equity classification. 
Interest on the Senior Notesterminated, and the Senior Convertible Notes (collectively,Company paid the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis byremaining outstanding accrued interest and other fees of approximately $2.2 million to fully satisfy all such outstanding obligations that were owed under the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default as well as covenants that place restrictions on the Company and certain of its subsidiaries.Whiting credit facility.
10.14. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the nine months ended September 30, 2017:
 (In thousands)
Balance at December 31, 2016$49,687
Liabilities incurred during period1,333
Liabilities settled during period(103)
Accretion expense during period(1)
1,998
Revisions to estimates(215)
Balance at September 30, 2017$52,700
___________________
2022:
(In thousands)
(1)Balance at December 31, 2021Included$62,416 
Liabilities assumed in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations.Merger87,265 
Liabilities incurred during period412 
Liabilities settled during period(1,816)
Accretion expense during period4,987 
Liabilities settled through divestitures(1)
(8,535)
Balance at September 30, 2022$144,729 

__________________ 
(1)    Includes $8.5 million of liabilities that were settled through the Rio Blanco County Divestiture. See Note 10—Divestitures for additional information.
Accretion expense is included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations. At September 30, 2017,2022, the current portion of the total ARO balance was approximately $0.3$25.0 million and wasis included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

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15. Income Taxes
The Company’s effective tax rate for the three and nine months ended September 30, 20172022 was 31.5%(0.1)% and 41.2%, respectively. For the three months ended September 30, 2017, the(0.3)% of pre-tax income from continuing operations, respectively, as compared to an effective tax rate was lower than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the portion of OMP’s earnings allocated to the non-controlling public limited partners, which are not subject to tax for the Company, and the permanent differences related to amounts expensed for book purposes versus the amounts deductible for0.0% of pre-tax income tax purposes related to equity-based compensation vesting at prices lower than the grant date values. For the nine months ended September 30, 2017, the effective tax rate was higher than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the permanent differences related to amounts expensed for book purposes versus the amounts deductible for income tax purposes related to equity-based compensation vesting at prices higher than the grant date values and non-deductible compensation, offset by the portion of OMP’s earnings allocated to the non-controlling public limited partners, which are not subject to tax for the Company.
The Company’s effective tax rate for the three and nine months ended September 30, 2016 was 33.0% and 34.0%, respectively. For the three and nine months ended September 30, 2016, the effective tax rates were lower than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the impact of permanent differences on pre-tax loss for these periods. The permanent differences for these periods were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to equity-based compensation vesting at prices lower than the grant date values during the three and nine months ended September 30, 2016.
12. Equity-Based Compensation
Restricted stock awards.The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock awards is based on the closing sales price of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.
During the nine months ended September 30, 2017, employees and non-employee directors of the Company were granted restricted stock awards equal to 1,624,810 shares of common stock with a $15.08 weighted average grant date per share value. Equity-based compensation expense recorded for restricted stock awardsfrom continuing operations for the three and nine months ended September 30, 2017 was $4.9 million and $15.2 million, respectively, and $4.8 million and $15.5 million2021.
The effective tax rates from continuing operations for the three and nine months ended September 30, 2016, respectively. 2022 and 2021 were lower than the statutory federal rate of 21% primarily as a result of the Company’s valuation allowance, a majority of which was released as of September 30, 2022. This benefit was partially offset by the impacts of state income taxes.
The Company initially recorded a valuation allowance against substantially all of its net deferred tax assets as of March 31, 2020. As of each reporting date, the Company assesses the available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to realize its deferred tax assets. A significant piece of objective positive evidence that the Company has evaluated is the cumulative income earned during the periods since the Company and Whiting each emerged from voluntary restructuring under Chapter 11 of the Bankruptcy Code in 2020. This source of objective positive evidence, combined with the indefinite lives for many of the Company’s deferred tax assets and projections of future taxable income led the Company to determine that there is sufficient positive evidence to conclude that it is more likely than not that the Company will realize the majority of its net deferred tax assets and release a portion of the valuation allowance previously recorded. The Company applied the intraperiod tax allocation rules in accordance with ASC 740-20 and allocated a portion of the income tax benefit associated with the release of the valuation allowance to continuing operations.
On July 1, 2022, the Company completed the Merger (see Note 2—Summary of Significant Accounting Policies for additional information), which qualified as a tax-free reorganization for U.S. federal income tax purposes. The Company recognized a net deferred tax asset of $250.2 million in its purchase price allocation as of the acquisition date to reflect the difference between the tax basis and the fair value of Whiting’s assets acquired and liabilities assumed. The net deferred tax asset includes the tax effected benefit of federal net operating loss carryforwards of $1.1 billion that were acquired in the Merger and are subject to an annual limitation of $7.0 million under Section 382 of the Internal Revenue Code of 1986 (the “Code”). Upon completion of the Merger, both the Company and Whiting experienced an “ownership change” as defined by the Code; however, the limitations anticipated as a result of these ownership changes are not expected to have a material impact on the realizability of the Company’s deferred tax assets. Determining the limitations under Section 382 of the Code is technical and highly complex, and upon future analysis the Company may determine that its ability to take advantage of its net operating loss carryforwards or other tax benefits may be limited to a greater extent than currently anticipated.
The Company’s estimated valuation allowance as of September 30, 2022 was $133.3 million, which decreased $266.5 million from $399.8 million as of December 31, 2021. The Company expects to release the majority of the remaining valuation allowance through the annualized effective tax rate in the fourth quarter of 2022 and anticipates maintaining a valuation allowance of approximately $9 million against state net operating losses acquired in the Merger.
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16. Equity-Based Compensation
The Company has granted restricted stock awards (“RSAs”), restricted stock units (“RSUs”), performance share units (“PSUs”), leveraged stock units (“LSUs”) and phantom unit awards under the 2020 Long Term Incentive Plan (the “2020 LTIP”). In accordance with the FASB’s authoritative guidance for share-based payments, the Company accounts for the RSAs, RSUs, PSUs and LSUs as equity classified awards and the phantom unit awards as liability classified awards.
Equity-based compensation expense from continuing operations is includedrecognized in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.
Performance share units. The Company has granted performance share units (“PSUs”) to officers of During the Company under its Amendedthree and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock.
During the nine months ended September 30, 2017, officers of2022, the Company were granted 509,800 PSUs with a $16.89 weighted average grant date per share value.recognized $30.7 million and $40.3 million in equity-based compensation expenses related to equity classified awards, respectively. During the three and nine months ended September 30, 2021, the Company recognized $4.1 million and $10.5 million in equity-based compensation expenses related to equity classified awards, respectively. Equity-based compensation expense recorded for PSUsexpenses related to liability classified awards were $2.1 million and $2.5 million during the three and nine months ended September 30, 2022, respectively. Equity-based compensation expenses related to liability classified awards were not material for the three and nine months ended September 30, 20172021.
Pursuant to the Merger Agreement, at the effective time of the Merger, the Company assumed the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “Whiting Plan”) and the outstanding RSUs and PSUs granted under the Whiting Plan, and accordingly (i) all shares remaining available for issuance under the Whiting Plan as of the Merger were automatically converted into shares of the Company’s common stock, available for issuance under the Whiting Plan and (ii) all such RSUs and PSUs were automatically converted into RSUs and PSUs, respectively, that, to the extent earned, will be settled in shares of the Company’s common stock, subject to appropriate adjustments to the number of shares subject to each award, resulting in the following as of July 1, 2022: (x) 1,611,725 shares of the Company’s common stock remaining available for issuance to eligible participants under the Whiting Plan, (y) 335,386 shares of the Company’s common stock subject to RSUs assumed under the Whiting Plan and (z) 275,310 shares of the Company’s common stock subject to PSUs assumed under the Whiting Plan. The number of PSUs assumed by the Company was $1.6determined based upon the change-in-control provisions contained in the original award agreement at the greater of (i) the target number of PSUs subject to such award and (ii) the actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of the Merger. Upon completion of the Merger, the Whiting RSUs and PSUs were subject to time-based vesting criteria. The fair value of the RSU and PSU awards assumed by the Company was $73.3 million, including $27.4 million that was attributable to pre-Merger services and $5.1recorded as a part of the consideration transferred and $45.9 million respectively,that is attributable to post-Merger services that will be recognized as equity-based compensation expense in the post-combination period. See Note 9—Acquisitions for additional information.
Restricted stock awards. The Company previously granted RSAs, which are legally issued shares, to non-employee directors of Oasis under the 2020 LTIP which were initially scheduled to vest over a three-year period subject to a service condition. The fair value was based on the closing price of the Company’s common stock at the date of grant.
Pursuant to the 2020 LTIP and $1.0 millionRSA award agreements, each outstanding RSA became fully vested upon completion of the Merger due to a “change in control.” As a result, 64,920 outstanding RSAs became fully vested on July 1, 2022. There were no outstanding RSAs at September 30, 2022.
Restricted stock units. The Company has granted RSUs, which are contingent shares with a service-based vesting condition, to employees and $3.2 million fornon-employee directors under the three2020 LTIP. The RSUs granted to employees vest ratably each year over a three-year or four-year period, and the RSUs granted to non-employee directors vest over a one-year period. The fair value is based on the closing price of the Company’s common stock on the date of grant or, if applicable, the date of modification. The Company recognizes compensation expense ratably over the requisite service period.
No employee RSUs were granted during the nine months ended September 30, 2016, respectively. Equity-based compensation expense is included in general and administrative expenses on2022. During the Company’s Condensed Consolidated Statementsnine months ended September 30, 2021, the Company granted 443,836 employee RSUs with a weighted average grant date per share value of Operations.$51.64. On August 31, 2022, the Company granted 13,920 RSUs to non-employee directors with a grant date per share value of $141.55.
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Performance share units. The Company accounted for thesehas granted PSUs as equity awards pursuant to certain employees under the FASB’s authoritative guidance for share-based payments.2020 LTIP. PSUs are contingent shares that may be earned over three-year and four-year performance periods. The number of PSUs to be earned iswas initially subject to a market condition which isthat was based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the applicable performance periods.periods, with 50% of the PSU awards eligible to be earned based on performance relative to a certain group of the Company’s oil and gas peers and 50% of the PSU awards eligible to be earned based on performance relative to the broad-based Russell 2000 index. Depending on the Company’s TSR performance relative to the defined peer group, award recipients willcould earn between 0% and 200%150% of target. Pursuant to the PSU award agreements, the number of PSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the initial PSUs granted. All compensation expense related toperformance criteria measured based on the PSUs will be recognized if the requisitetruncated performance period is fulfilled, even if the market condition is not achieved.
The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading daysending immediately prior to the starteffective time of the performance cycle for the Company and each of its peers. Volatility was calculated from the daily historical returns of 30-day volume weighted average stock prices over a historical period for the Company and each of its peers.“change in control.” The correlation coefficients are measurescompletion of the strength of the linear relationship betweenMerger on July 1, 2022 represented a “change in control” such that 250,009 PSUs were earned by award recipients and amongst the Company and its peers estimated based on historical stock price data.converted into time-based awards.

The following assumptionsNo PSUs were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the nine months ended September 30, 2017:
Risk-free interest rate1.18% - 1.66%
Oasis volatility17.16%
OMPunit-based compensation.In2022. During the nine months ended September 2017, OMP GP adopted30, 2021, the Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“OMP LTIP”). The OMP LTIP provides for the grant, from time to time at the discretion of the board of directors of OMP GP, of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other unit-based awards or cash awards and includes any tandem distribution equivalent rights with respect to certain awards. The purpose of awards under the OMP LTIP is to provide additional incentive compensation to individuals providing services to OMP, and to align the economic interests of such individuals with the interests of OMP’s unitholders.
The aggregate number of common units that may be issued pursuant to any and all awards under the OMP LTIP shall initially be equal to 1,842,500 common units, subject to proportionate adjustment in the event of unit splits and similar events. Additionally, each year, the total number of common units that may be issued pursuant to the OMP LTIP shall increase by 1% of the number of common units outstanding on a fully diluted basis (calculated by adding to the number of common units outstanding, all outstanding securities convertible into common units on such date on an as-converted basis). Common units subject to awards that are canceled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of common units will be available for delivery pursuant to other awards.
In connection with the OMP IPO, certain directors of OMP wereCompany granted 11,766 restricted unit awards which vest over a one-year period183,915 PSUs with a weighted average grant date per share value of $63.95.
Leveraged stock units. The Company has granted LSUs to certain employees under the 2020 LTIP. LSUs are contingent shares that may be earned over a three-year or four-year performance period. The number of LSUs to be earned was initially subject to a market condition, which was based on the TSR performance of the Company’s common stock measured against specific premium return objectives. Depending on the Company’s TSR performance, award recipients could earn between 0% and 300% of target; however, the number of shares delivered in respect to these awards during the grant cycle could not exceed ten times the fair value of $17.00the award on the grant date. Pursuant to LSU award agreements, the number of LSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of the “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 787,218 LSUs were earned by award recipients and converted into time-based awards.
No LSUs were granted during the nine months ended September 30, 2022. During the nine months ended September 30, 2021, the Company granted 262,406 LSUs with a weighted average grant date per share value of $78.79.
Unvested equity awards. At September 30, 2022, there were 1,417,189 outstanding and unvested equity-based compensation awards (including equity awards assumed in the Merger), all of which are time-based awards subject to vesting over applicable service periods.
17. Stockholder's Equity
Authorized Shares of Common Stock
On June 28, 2022, the Company’s stockholders approved an amendment to the Amended and Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 60,000,000 to 120,000,000 in connection with the Merger. The amendment became effective on July 1, 2022.
Issuance of Common Stock
Pursuant to the Merger Agreement, each share of Whiting common stock issued and outstanding immediately prior to the effective time of the Merger was converted into the right to receive 0.5774 shares of common stock, par value $0.01 per share, of the Company. As a result of the completion of the Merger on July 1, 2022, the Company issued 22,671,871 shares of common stock to Whiting stockholders.
Dividends
Base dividends. During the nine months ended September 30, 2022 and 2021, the Company paid base dividends of $2.42 per share of common stock and $1.13 per share of common stock, respectively.
On November 2, 2022, the Company declared a base dividend of $1.25 per share of common stock. The dividend will be payable on November 29, 2022 to shareholders of record as of November 15, 2022.
Variable dividends. During the nine months ended September 30, 2022, the Company paid variable dividends of $5.94 per share of common stock. No variable dividends were paid during the nine months ended September 30, 2021.
On November 2, 2022, the Company declared a variable dividend of $2.42 per share of common stock. The dividend will be payable on November 29, 2022 to shareholders of record as of November 15, 2022.
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Special dividends. In connection with the Merger, the Board of Directors of the Company declared a special dividend of $15.00 per share of common stock (the “Special Dividend”) that was paid on July 8, 2022 to shareholders of record as of June 29, 2022. During the nine months ended September 30, 2021, the Company paid a special dividend of $4.00 per share of common stock. The Special Dividend was accounted for separately from the Merger and recognized as a reduction of retained earnings during the second quarter of 2022, which was the period when the Special Dividend was declared.
Share-Repurchase Program
In February 2022, the Board of Directors of the Company authorized a share-repurchase program covering up to $150.0 million of the Company’s common stock. During the three and nine months ended September 30, 2022, the Company repurchased 1,174,756 shares of common stock at a weighted average price of $106.25 per common unit. OMP accountedshare for these restricted unit awardsa total cost of $124.8 million.
In August 2022, the Board of Directors of the Company authorized a new share-repurchase program covering up to $300.0 million of the Company’s common stock, which resulted in the expiration of the $150.0 million share-repurchase program. The Company has not repurchased any shares of common stock under this new share-repurchase program.
The Company repurchased no shares of common stock during the three months ended September 30, 2021. During the nine months ended September 30, 2021, the Company repurchased 190,783 shares of common stock at a weighted average price of $76.30 per common share for a total cost of $14.6 million.
Warrants
The following table summarizes the Company’s outstanding warrants as of September 30, 2022:
Warrants(1)
Exercise Price(2)
Legacy Oasis894,374$75.57 
Legacy Whiting - Series A2,778,963$116.37 
Legacy Whiting - Series B1,395,112$133.70 
Total5,068,449
__________________ 
(1)Represents the number of warrants in terms of shares of Chord common stock. During the three and nine months ended September 30, 2022, there were 98,518 and 626,998 warrants exercised, respectively.
(2)The exercise price of legacy Whiting warrants was adjusted in accordance with the Merger Agreement.
Legacy Oasis warrants. On November 19, 2020, the Company entered into a Warrant Agreement with Computershare Inc. and Computershare Trust Company N.A., as warrant agent. The warrants, which are indexed to the Company’s common stock and are classified as equity, awards, pursuantare exercisable until November 19, 2024, at which time all unexercised warrants will expire and the rights of the holders of such warrants to purchase common stock will terminate. In the event that a holder of a warrant elects to exercise their option to acquire shares of the Company’s common stock, the warrant is required to be settled through physical settlement or net share settlement.
The warrants were initially exercisable for a price of $94.57 per warrant. The number of shares of Chord common stock for which a warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock. Pursuant to the FASB’s authoritative guidanceterms of the Warrant Agreement, the exercise price per warrant decreased to $75.57 per warrant effective June 30, 2022 in connection with the payment of the Special Dividend.
No holder of a warrant, by virtue of holding or having a beneficial interest in a warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the warrants.
Assumed Whiting warrants. Pursuant to the Merger Agreement, all of Whiting’s outstanding warrants immediately prior to the effective time of the Merger were assumed by the Company at the closing of the Merger. Prior to the Merger, each legacy Whiting warrant was exercisable for one share of Whiting common stock. Following the completion of the Merger and the Company’s assumption of the legacy Whiting warrants, each such warrant was exercisable for 0.5774 shares of the Company’s common stock, which reflects an adjustment in accordance with the exchange ratio under the Merger Agreement. Also, in accordance with the Merger Agreement, the exercise price of each such legacy Whiting warrant per share of the Company’s common stock was adjusted to equal the quotient of (x) the exercise price of such warrant per share of Whiting common stock immediately prior to the effective time of the Merger less $6.25 divided by (y) the exchange ratio of 0.5774.
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Therefore, as a result of the completion of the Merger on July 1, 2022, the Company assumed (i) 4,833,455 legacy Whiting Series A Warrants which were exercisable for an aggregate amount of 2,790,837 shares of the Company’s common stock at an exercise price of $116.37 per share and (ii) 2,418,832 legacy Whiting Series B Warrants which were exercisable for an aggregate amount of 1,396,634 shares of the Company’s common stock at an exercise price of $133.70 per share.
In the event that a holder of Whiting warrants elects to exercise their option to acquire shares of the Company’s common stock, the Company shall issue a net number of exercised shares of common stock. The net number of exercised shares is calculated as (i) the number of Whiting warrants exercised multiplied by (ii) the difference between the 30 day daily volume weighted average price of the common stock leading up to the exercise date and the relevant exercise price, calculated as a percentage of the current market price on the exercise date.
The legacy Whiting Series A Warrants are exercisable until September 1, 2024 and the legacy Whiting Series B Warrants are exercisable until September 1, 2025, at which respective times all unexercised Whiting warrants will expire and the rights of the holders of such Whiting warrants to acquire common stock will terminate. Pursuant to the Whiting warrant agreements, no holder of a Whiting warrant, by virtue of holding or having a beneficial interest in a Whiting warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the Whiting warrants.
The number of shares of Chord common stock for which a Whiting warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock.
18. Earnings Per Share
The Company calculates earnings per share under the two-class method. During the third quarter of 2022, the Company granted RSUs to non-employee directors which include non-forfeitable rights to dividends and are therefore considered “participating securities.” Accordingly, effective September 30, 2022, the Company has computed earnings per share under the two-class earnings allocation method. The two-class method is an earnings allocation formula that computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.
Basic earnings per share amounts have been computed as (i) net income (loss) (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the reallocation of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented. The Company calculates diluted earnings per share under both the two-class method and treasury stock method and reports the more dilutive of the two calculations.
The following table summarizes the basic and diluted earnings per share for the periods presented:
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Three Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (In thousands, except per share data)
Net income from continuing operations$941,609 $41,755 $1,052,897 $765 
Distributed and undistributed earnings allocated to participating securities(113)— (47)— 
Net income from continuing operations attributable to common stockholders (basic)941,496 41,755 1,052,850 765 
Reallocation of distributed and undistributed earnings allocated to participating securities4— 2 — 
Net income from continuing operations attributable to common stockholders (diluted)$941,500 $41,755 $1,052,852 $765 
Weighted average common shares outstanding:
Basic weighted average common shares outstanding41,31819,81226,806 19,905 
Dilutive effect of share-based awards1,147 956 1,160 603 
Dilutive effect of warrants642 18 472 — 
Diluted weighted average common shares outstanding43,107 20,786 28,438 20,508 
Basic earnings per share from continuing operations$22.79 $2.11 $39.28 $0.04 
Diluted earnings per share from continuing operations$21.84 $2.01 $37.02 $0.04 
Anti-dilutive weighted average common shares:
Potential common shares4,874 2,152 2,436 2,295 

For the three and nine months ended September 30, 2022 and 2021, the diluted earnings per share calculation excludes the impact of unvested share-based payments. Equity-based compensation expense is recognized ratably overawards and outstanding warrants that were anti-dilutive under the requisite service period. Equity-based compensation expense recorded for restricted unit awardstreasury stock method.
Basic and diluted earnings per share from discontinued operations were calculated using the two-class method. Basic earnings (loss) per share from discontinued operations was $(1.45) and $15.88 for the three and nine months ended September 30, 2017 is included in general2022, respectively and administrative expenses on the the Company’s Condensed Consolidated Statements of Operations.
13. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis common stockholders by the weighted average number of shares outstanding$1.52 and $5.07 for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of unvested restricted stock awards and contingently issuable shares related to PSUs and senior convertible notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to the income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share.
The following is a calculation of the basic and diluted weighted average shares outstanding for the three and nine months ended September 30, 20172021, respectively. Diluted earnings (loss) per share from discontinued operations was $(1.39) and 2016: 
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands)
Basic weighted average common shares outstanding233,389
 177,120
 233,248
 172,360
Dilutive effect of restricted stock awards and PSUs—
 —
 —
 —
Diluted weighted average common shares outstanding233,389
 177,120
 233,248
 172,360
During$14.97 for the three and nine months ended September 30, 20172022, respectively, and 2016,$1.45 and $4.92 for the Company incurred a net loss and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested stock awards. The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands)
Restricted stock awards and PSUs5,841
 5,140
 5,988
 4,935

The Company issued its Senior Convertible Notes in September 2016 (see Note 9 – Long-Term Debt). The Company has the option to settle conversions of its Senior Convertible Notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of the three and nine months ended September 30, 2017, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for the three and nine months ended September 30, 2017.2021, respectively.
14. Business Segment Information
The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The Company’s midstream services business segment (OMS) performs produced and flowback water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from produced and flowback water pipeline transport, produced and flowback water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering, blending, stabilization and transportation. The Company’s well services business segment (OWS) performs completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s Condensed Consolidated Statements of Operations. These segments represent the Company’s three operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly.

Management evaluates the performance of the Company’s business segments based on operating income. The following table summarizes financial information for the Company’s three business segments for the periods presented:
 
Exploration and
Production
 Midstream Services Well Services Eliminations Consolidated
 (In thousands)
Three months ended September 30, 2017: 
Revenues from non-affiliates$269,843
 $18,767
 $16,138
 $—
 $304,748
Inter-segment revenues—
 28,893
 31,025
 (59,918) —
Total revenues269,843
 47,660
 47,163
 (59,918) 304,748
Operating income3,484
 25,194
 10,802
 (7,086) 32,394
Other income (expense)(92,319) (15) 30
 —
 (92,304)
Income (loss) before income taxes including non-controlling interests$(88,835) $25,179
 $10,832
 $(7,086) $(59,910)
  
Three months ended September 30, 2016: 
Revenues from non-affiliates$158,183
 $8,487
 $10,641
 $—
 $177,311
Inter-segment revenues—
 20,790
 11,818
 (32,608) —
Total revenues158,183
 29,277
 22,459
 (32,608) 177,311
Operating income (loss)(41,857) 16,525
 1,572
 (1,942) (25,702)
Other income (expense)(24,476) (460) 5
 —
 (24,931)
Income (loss) before income taxes$(66,333) $16,065
 $1,577
 $(1,942) $(50,633)
  
Nine months ended September 30, 2017: 
Revenues from non-affiliates$761,450
 $48,939
 $33,566
 $—
 $843,955
Inter-segment revenues—
 76,674
 68,028
 (144,702) —
Total revenues761,450
 125,613
 101,594
 (144,702) 843,955
Operating income (loss)(12,972) 69,059
 9,161
 (7,383) 57,865
Other income (expense)(59,027) (13) 34
 —
 (59,006)
Income (loss) before income taxes including non-controlling interests$(71,999) $69,046
 $9,195
 $(7,383) $(1,141)
  
Nine months ended September 30, 2016: 
Revenues from non-affiliates$434,835
 $22,380
 $29,459
 $—
 $486,674
Inter-segment revenues—
 65,650
 45,023
 (110,673) —
Total revenues434,835
 88,030
 74,482
 (110,673) 486,674
Operating income (loss)(175,480) 49,724
 3,420
 (6,795) (129,131)
Other income (expense)(155,595) (462) 42
 —
 (156,015)
Income (loss) before income taxes$(331,075) $49,262
 $3,462
 $(6,795) $(285,146)
  
At September 30, 2017: 
Property, plant and equipment, net$5,595,611
 $577,883
 $43,175
 $(181,051) $6,035,618
Total assets(1)
5,930,040
 589,506
 52,717
 (181,051) 6,391,212
At December 31, 2016:         
Property, plant and equipment, net$5,620,558
 $424,197
 $47,189
 $(172,377) $5,919,567
Total assets(1)
5,868,747
 431,095
 51,167
 (172,377) 6,178,632
___________________
(1)Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

15.19. Commitments and Contingencies
The Company has various contractual obligations in the normal course of its operations. As of September 30, 2017,2022, the Company’s material off-balance sheet arrangements and transactions include $5.9 million in outstanding letters of credit under the Credit Facility and $8.0 million in net surety bond exposure issued as financial assurance on certain agreements.
As of September 30, 2022, there have been no material changes to the Company’s future commitments asand contingencies disclosed in Note 1622 — Commitments and Contingencies in the Company’s 20162021 Annual Report.Report, except as set forth below.
Litigation.Volume commitment agreements. In connection with the Merger, the Company assumed certain agreements with an aggregate requirement to deliver a minimum quantity of crude oil from the Company’s Sanish field in Mountrail County, North Dakota through June 2024. As of September 30, 2022, the Company had remaining commitments to deliver approximately 12.3 million barrels (“MMBbl”) of crude oil under these agreements. The Company is partybelieves its production and reserves at the Sanish field are sufficient to various legal and/or regulatory proceedings from timefulfill this delivery commitment, and therefore expects to time arisingavoid any payments for deficiencies under this contract.
Additionally, the Company assumed two buy/sell transportation agreements with an aggregate requirement to deliver a minimum quantity of crude oil through July 2024. As of September 30, 2022, the Company had remaining commitments to deliver approximately 4.7 MMBbl of crude oil under these agreements. The Company recorded the fair value of these agreements as derivative liabilities in the ordinary courseCondensed Consolidated Balance Sheets as of business. WhenSeptember 30, 2022. See Note 7—Derivative Instruments for additional information.
Lease commitments. In connection with the Merger, the Company determinesassumed approximately $15.1 million of operating lease
31
Table of Contents
liabilities for office buildings and operating equipment with lease terms through 2030 and approximately $1.6 million of finance lease liabilities for vehicles with lease terms through 2026.
Chapter 11 bankruptcy claims. On April 1, 2020, Whiting and certain of its subsidiaries (the “Debtors”) commenced voluntary cases (the “Whiting Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code. On June 30, 2020, the Debtors filed their proposed Joint Chapter 11 Plan of Reorganization of Whiting and its Debtor affiliates (as amended, modified and supplemented, the “Whiting Plan”). On August 14, 2020, the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) confirmed the Whiting Plan and on September 1, 2020, the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Whiting Chapter 11 Cases.
The filing of the Whiting Chapter 11 Cases allowed Whiting to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves Whiting from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. The claims resolution process is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court. To the extent that a loss is probable of occurring and is reasonably estimable,the Bankruptcy Court allows any unsecured claims against the Company, accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcomeclaims may be material,satisfied through an issuance of the Company’s common stock or inother remedy or agreement under and pursuant to the judgmentWhiting Plan. In connection with the closing of management, the matter should otherwise be disclosed.
Mirada litigation.On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and Oasis Midstream Services LLC, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated byMerger on July 1, 2022, the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgmentassumed Whiting’s obligations with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that MiradaWhiting Plan and, accordingly, has a rightreserved 1,224,840 shares of common stock for potential future distribution to participatecertain general unsecured claimants whose claim values are pending resolution in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gatheringBankruptcy Court.
Arguello Inc. and gas gatheringFreeport-McMoRan Oil & Gas LLC. Whiting Oil and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receiveGas Corporation (“WOG”), a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims. Discovery is ongoing, and trial is currently scheduled for July 2018. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interestswholly-owned subsidiary of the Company, had interests in their current assetsfederal oil and future midstream opportunities and related revenues in Wild Basin.

16. Condensed Consolidating Financial Information
The Notes (see Note 9 – Long-Term Debt) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s operating units, including OMP (see Note 3 – Oasis Midstream Partners LP), which is accounted for on a consolidated basis, do not guarantee the Notes (“Non-Guarantor Subsidiaries”).
The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), its Guarantors on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors.

Condensed Consolidating Balance Sheet
 September 30, 2017
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 Non-Guarantor Subsidiaries 
Intercompany
Eliminations
 Consolidated
 (In thousands)
ASSETS         
Current assets         
Cash and cash equivalents$178
 $8,310
 $—
 $—
 $8,488
Accounts receivable, net—
 285,325
 58
 —
 285,383
Accounts receivable - affiliates136,004
 34,226
 5,611
 (175,841) —
Inventory—
 17,169
 —
 —
 17,169
Prepaid expenses465
 10,153
 29
 —
 10,647
Derivative instruments—
 692
 —
 —
 692
Other current assets—
 65
 —
 —
 65
Total current assets136,647
 355,940
 5,698
 (175,841) 322,444
Property, plant and equipment

 

   

 

Oil and gas properties (successful efforts method)—
 7,640,785
 —
 —
 7,640,785
Other property and equipment—
 261,444
 522,098
 —
 783,542
Less: accumulated depreciation, depletion, amortization and impairment—
 (2,358,848) (29,861) —
 (2,388,709)
Total property, plant and equipment, net—
 5,543,381
 492,237
 —
 6,035,618
Investments in and advances to subsidiaries4,535,693
 376,528
 —
 (4,912,221) —
Derivative instruments—
 703
 —
 —
 703
Deferred income taxes269,704
 —
 —
 (269,704) —
Long-term inventory—
 10,885
 —
 —
 10,885
Other assets—
 19,614
 1,948
 —
 21,562
Total assets$4,942,044
 $6,307,051
 $499,883
 $(5,357,766) $6,391,212
LIABILITIES AND STOCKHOLDERS’ EQUITY         
Current liabilities         
Accounts payable$—
 $16,348
 $—
 $—
 $16,348
Accounts payable - affiliates33,885
 141,615
 341
 (175,841) —
Revenues and production taxes payable—
 169,361
 —
 —
 169,361
Accrued liabilities(8) 188,375
 5,790
 —
 194,157
Accrued interest payable19,872
 449
 4
 —
 20,325
Derivative instruments—
 16,412
 —
 —
 16,412
Advances from joint interest partners—
 5,095
 —
 —
 5,095
Total current liabilities53,749
 537,655
 6,135
 (175,841) 421,698
Long-term debt1,945,613
 395,000
 —
 —
 2,340,613
Deferred income taxes—
 778,039
 —
 (269,704) 508,335
Asset retirement obligations—
 51,156
 1,257
 —
 52,413
Derivative instruments—
 3,703
 —
 —
 3,703
Other liabilities—
 5,805
 —
 —
 5,805
Total liabilities1,999,362
 1,771,358
 7,392
 (445,545) 3,332,567
Stockholders’ equity         
Capital contributions from affiliates—
 3,282,946
 261,312
 (3,544,258) —
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,639,488 shares issued and 237,312,881 shares outstanding2,348
 —
 —
 —
 2,348
Treasury stock, at cost: 1,326,607 shares(22,132) —
 —
 —
 (22,132)
Additional paid-in-capital2,369,098
 8,849
 —
 (8,849) 2,369,098
Retained earnings593,368
 1,127,935
 —
 (1,127,935) 593,368
Oasis share of stockholders’ equity2,942,682
 4,419,730
 261,312
 (4,681,042) 2,942,682
Non-controlling interests—
 115,963
 231,179
 (231,179) 115,963

Total stockholders’ equity2,942,682
 4,535,693
 492,491
 (4,912,221) 3,058,645
Total liabilities and stockholders’ equity$4,942,044
 $6,307,051
 $499,883
 $(5,357,766) $6,391,212

Condensed Consolidating Balance Sheet
 December 31, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 Consolidated
 (In thousands)
ASSETS       
Current assets       
Cash and cash equivalents$166
 $11,060
 $—
 $11,226
Accounts receivable, net—
 204,335
 —
 204,335
Accounts receivable - affiliates252,000
 27,619
 (279,619) —
Inventory—
 10,648
 —
 10,648
Prepaid expenses275
 7,348
 —
 7,623
Derivative instruments—
 362
 —
 362
Other current assets—
 4,355
 —
 4,355
Total current assets252,441
 265,727
 (279,619) 238,549
Property, plant and equipment

 

 

 

Oil and gas properties (successful efforts method)—
 7,296,568
 —
 7,296,568
Other property and equipment—
 618,790
 —
 618,790
Less: accumulated depreciation, depletion, amortization and impairment—
 (1,995,791) —
 (1,995,791)
Total property, plant and equipment, net—
 5,919,567
 —
 5,919,567
Investments in and advances to subsidiaries4,451,192
 —
 (4,451,192) —
Deferred income taxes220,058
 —
 (220,058) —
Other assets—
 20,516
 —
 20,516
Total assets$4,923,691
 $6,205,810
 $(4,950,869) $6,178,632
LIABILITIES AND STOCKHOLDERS’ EQUITY       
Current liabilities       
Accounts payable$—
 $4,645
 $—
 $4,645
Accounts payable - affiliates27,619
 252,000
 (279,619) —
Revenues and production taxes payable—
 139,737
 —
 139,737
Accrued liabilities12
 119,161
 —
 119,173
Accrued interest payable38,689
 315
 —
 39,004
Derivative instruments—
 60,469
 —
 60,469
Advances from joint interest partners—
 7,597
 —
 7,597
Other current liabilities—
 10,490
 —
 10,490
Total current liabilities66,320
 594,414
 (279,619) 381,115
Long-term debt1,934,214
 363,000
 —
 2,297,214
Deferred income taxes—
 733,587
 (220,058) 513,529
Asset retirement obligations—
 48,985
 —
 48,985
Derivative instruments—
 11,714
 —
 11,714
Other liabilities—
 2,918
 —
 2,918
Total liabilities2,000,534
 1,754,618
 (499,677) 3,255,475
Stockholders’ equity       
Capital contributions from affiliates—
 3,388,893
 (3,388,893) —
Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding2,331
 —
 —
 2,331
Treasury stock, at cost: 856,892 shares(15,950) —
 —
 (15,950)
Additional paid-in-capital2,345,271
 8,743
 (8,743) 2,345,271
Retained earnings591,505
 1,053,556
 (1,053,556) 591,505
Total stockholders’ equity2,923,157
 4,451,192
 (4,451,192) 2,923,157
Total liabilities and stockholders’ equity$4,923,691
 $6,205,810
 $(4,950,869) $6,178,632

Condensed Consolidating Statement of Operations
 Three Months Ended September 30, 2017
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 Combined Non-Guarantor Subsidiaries 
Intercompany
Eliminations
 Consolidated
 (In thousands)
Revenues         
Oil and gas revenues$—
 $248,648
 $—
 $—
 $248,648
Bulk oil sales—
 21,195
 —
 —
 21,195
Midstream revenues—
 15,828
 2,939
 —
 18,767
Well services revenues—
 16,138
 —
 —
 16,138
Total revenues—
 301,809
 2,939
 —
 304,748
Operating expenses         
Lease operating expenses—
 45,334
 —
 —
 45,334
Midstream operating expenses—
 3,621
 680
 —
 4,301
Well services operating expenses—
 9,125
 —
 —
 9,125
Marketing, transportation and gathering expenses—
 15,028
 —
 —
 15,028
Bulk oil purchases—
 21,701
 —
 —
 21,701
Production taxes—
 21,052
 —
 —
 21,052
Depreciation, depletion and amortization—
 132,035
 254
 —
 132,289
Exploration expenses—
 854
 —
 —
 854
Impairment—
 139
 —
 —
 139
General and administrative expenses6,775
 15,375
 381
 —
 22,531
Total operating expenses6,775
 264,264
 1,315
 —
 272,354
Operating income (loss)(6,775) 37,545
 1,624
 —
 32,394
Other income (expense)         
Equity in earnings (loss) of subsidiaries(13,599) 1,605
 —
 11,994
 —
Net loss on derivative instruments—
 (54,310) —
 —
 (54,310)
Interest expense, net of capitalized interest(32,894) (4,476) (19) —
 (37,389)
Other income (expense)2
 (607) —
 —
 (605)
Total other expense(46,491) (57,788) (19) 11,994
 (92,304)
Income (loss) before income taxes(53,266) (20,243) 1,605
 11,994
 (59,910)
Income tax benefit12,052
 6,794
 —
 —
 18,846
Net income (loss) including non-controlling interests(41,214) (13,449) 1,605
 11,994
 (41,064)
Less: Net income attributable to non-controlling interests—
 150
 1,112
 (1,112) 150
Net income (loss) attributable to Oasis$(41,214) $(13,599) $493
 $13,106
 $(41,214)

Condensed Consolidating Statement of Operations
 Three Months Ended September 30, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 Consolidated
 (In thousands)
Revenues       
Oil and gas revenues$—
 $156,316
 $—
 $156,316
Bulk oil sales—
 1,867
 —
 1,867
Midstream revenues—
 8,487
 —
 8,487
Well services revenues—
 10,641
 —
 10,641
Total revenues—
 177,311
 —
 177,311
Operating expenses       
Lease operating expenses—
 35,696
 —
 35,696
Midstream operating expenses—
 2,617
 —
 2,617
Well services operating expenses—
 5,548
 —
 5,548
Marketing, transportation and gathering expenses—
 7,003
 —
 7,003
Bulk oil purchases—
 1,853
 —
 1,853
Production taxes—
 14,638
 —
 14,638
Depreciation, depletion and amortization—
 111,948
 —
 111,948
Exploration expenses—
 489
 —
 489
Impairment—
 382
 —
 382
General and administrative expenses5,930
 16,915
 —
 22,845
Total operating expenses5,930
 197,089
 —
 203,019
Gain on sale of properties—
 6
 —
 6
Operating loss(5,930) (19,772) —
 (25,702)
Other income (expense)       
Equity in loss of subsidiaries(1,140) —
 1,140
 —
Net gain on derivative instruments—
 20,847
 —
 20,847
Interest expense, net of capitalized interest(29,876) (1,850) —
 (31,726)
Loss on extinguishment of debt(13,793) —
 —
 (13,793)
Other income (expense)1
 (260) —
 (259)
Total other income (expense)(44,808) 18,737
 1,140
 (24,931)
Loss before income taxes(50,738) (1,035) 1,140
 (50,633)
Income tax benefit (expense)16,796
 (105) —
 16,691
Net loss$(33,942) $(1,140) $1,140
 $(33,942)


Condensed Consolidating Statement of Operations
 Nine Months Ended September 30, 2017
 Parent/
Issuer		 Combined
Guarantor
Subsidiaries		 Combined Non-Guarantor Subsidiaries Intercompany
Eliminations		 Consolidated
 (In thousands)
Revenues         
Oil and gas revenues$—
 $704,533
 $—
 $—
 $704,533
Bulk oil sales—
 56,917
 —
 —
 56,917
Midstream revenues—
 46,000
 2,939
 —
 48,939
Well services revenues—
 33,566
 —
 —
 33,566
Total revenues—
 841,016
 2,939
 —
 843,955
Operating expenses         
Lease operating expenses—
 133,871
 —
 —
 133,871
Midstream operating expenses—
 10,211
 680
 —
 10,891
Well services operating expenses—
 21,115
 —
 —
 21,115
Marketing, transportation and gathering expenses—
 38,018
 —
 —
 38,018
Bulk oil purchases—
 57,683
 —
 —
 57,683
Production taxes—
 60,322
 —
 —
 60,322
Depreciation, depletion and amortization—
 383,992
 254
 —
 384,246
Exploration expenses—
 4,010
 —
 —
 4,010
Impairment—
 6,021
 —
 —
 6,021
General and administrative expenses21,374
 48,158
 381
 —
 69,913
Total operating expenses21,374
 763,401
 1,315
 —
 786,090
Operating income (loss)(21,374) 77,615
 1,624
 —
 57,865
Other income (expense)         
Equity in earnings of subsidiaries74,379
 1,605
 —
 (75,984) —
Net gain on derivative instruments—
 52,297
 —
 —
 52,297
Interest expense, net of capitalized interest(98,751) (11,778) (19) —
 (110,548)
Other income (expense)2
 (757) —
 —
 (755)
Total other income (expense)(24,370) 41,367
 (19) (75,984) (59,006)
Income (loss) before income taxes(45,744) 118,982
 1,605
 (75,984) (1,141)
Income tax benefit (expense)44,923
 (44,453) —
 —
 470
Net income (loss) including non-controlling interests(821) 74,529
 1,605
 (75,984) (671)
Less: Net income attributable to non-controlling interests—
 150
 1,112
 (1,112) 150
Net income (loss) attributable to Oasis$(821) $74,379
 $493
 $(74,872) $(821)

Condensed Consolidating Statement of Operations
 Nine Months Ended September 30, 2016
 Parent/
Issuer		 Combined
Guarantor
Subsidiaries		 Intercompany
Eliminations		 Consolidated
 (In thousands)
Revenues       
Oil and gas revenues$—
 $432,968
 $—
 $432,968
Bulk oil sales—
 1,867
 —
 1,867
Midstream revenues—
 22,380
 —
 22,380
Well services revenues—
 29,459
 —
 29,459
Total revenues—
 486,674
 —
 486,674
Operating expenses       
Lease operating expenses—
 98,283
 —
 98,283
Midstream operating expenses—
 6,095
 —
 6,095
Well services operating expenses—
 15,334
 —
 15,334
Marketing, transportation and gathering expenses—
 22,046
 —
 22,046
Bulk oil purchases—
 1,853
 —
 1,853
Production taxes—
 39,758
 —
 39,758
Depreciation, depletion and amortization—
 356,885
 —
 356,885
Exploration expenses—
 1,192
 —
 1,192
Impairment—
 3,967
 —
 3,967
General and administrative expenses19,776
 49,311
 —
 69,087
Total operating expenses19,776
 594,724
 —
 614,500
Loss on sale of properties—
 (1,305) —
 (1,305)
Operating loss(19,776) (109,355) —
 (129,131)
Other income (expense)       
Equity in loss of subsidiaries(110,454) —
 110,454
 —
Net loss on derivative instruments—
 (55,624) —
 (55,624)
Interest expense, net of capitalized interest(97,898) (7,546) —
 (105,444)
Gain on extinguishment of debt4,865
 —
 —
 4,865
Other income44
 144
 —
 188
Total other expense(203,443) (63,026) 110,454
 (156,015)
Loss before income taxes(223,219) (172,381) 110,454
 (285,146)
Income tax benefit34,891
 61,927
 —
 96,818
Net loss$(188,328) $(110,454) $110,454
 $(188,328)


Condensed Consolidating Statement of Cash Flows
 Nine Months Ended September 30, 2017
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 Combined Non-Guarantor Subsidiaries 
Intercompany
Eliminations
 Consolidated
 (In thousands)
Cash flows from operating activities:         
Net income (loss) including non-controlling interests$(821) $74,529
 $1,605
 $(75,984) $(671)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by (used in) operating activities:         
Equity in earnings of subsidiaries(74,379) (1,605) —
 75,984
 —
Depreciation, depletion and amortization—
 383,992
 254
 —
 384,246
Impairment—
 6,021
 —
 —
 6,021
Deferred income taxes(44,923) 44,453
 —
 —
 (470)
Derivative instruments—
 (52,297) —
 —
 (52,297)
Equity-based compensation expenses19,740
 711
 —
 —
 20,451
Deferred financing costs amortization and other11,399
 1,260
 7
 —
 12,666
Working capital and other changes:    

    
Change in accounts receivable115,996
 (87,610) (5,630) (103,778) (81,022)
Change in inventory—
 (235) —
 —
 (235)
Change in prepaid expenses(190) 1,013
 —
 —
 823
Change in other current assets—
 276
 —
 —
 276
Change in long-term inventory and other assets—
 (12,843) —
 —
 (12,843)
Change in accounts payable, interest payable and accrued liabilities(12,571) (62,542) 3,617
 103,778
 32,282
Change in other current liabilities—
 (10,490) —
 —
 (10,490)
Net cash provided by (used in) operating activities14,251
 284,633
 (147) —
 298,737
Cash flows from investing activities:         
Capital expenditures—
 (443,649) —
 —
 (443,649)
Proceeds from sale of properties—
 4,000
 —
 —
 4,000
Derivative settlements—
 (804) —
 —
 (804)
Advances from joint interest partners—
 (2,502) —
 —
 (2,502)
Net cash used in investing activities—
 (442,955) —
 —
 (442,955)
Cash flows from financing activities:         
Proceeds from revolving credit facility—
 764,000
 —
 —
 764,000
Principal payments on revolving credit facility—
 (732,000) —
 —
 (732,000)
Deferred financing costs—
 1,858
 (1,954) —
 (96)
Proceeds from issuance of Oasis Midstream common units, net of offering costs—
 —
 115,813
 —
 115,813
Purchases of treasury stock(6,182) —
 —
 —
 (6,182)
Investment in subsidiaries / capital contributions from parent(8,002) 121,714
 (113,712) —
 —
Other(55) —
 —
 —
 (55)
Net cash provided by (used in) financing activities(14,239) 155,572
 147
 —
 141,480
Increase (decrease) in cash and cash equivalents12
 (2,750) —
 —
 (2,738)
Cash and cash equivalents at beginning of period166
 11,060
 —
 —
 11,226
Cash and cash equivalents at end of period$178
 $8,310
 $—
 $—
 $8,488

Condensed Consolidating Statement of Cash Flows
 Nine Months Ended September 30, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 Consolidated
 (In thousands)
Cash flows from operating activities:       
Net loss$(188,328) $(110,454) $110,454
 $(188,328)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:       
Equity in loss of subsidiaries110,454
 —
 (110,454) —
Depreciation, depletion and amortization—
 356,885
 —
 356,885
Gain on extinguishment of debt(4,865) —
 —
 (4,865)
Loss on sale of properties—
 1,305
 —
 1,305
Impairment—
 3,967
 —
 3,967
Deferred income taxes(34,891) (61,927) —
 (96,818)
Derivative instruments—
 55,624
 —
 55,624
Equity-based compensation expenses18,195
 566
 —
 18,761
Deferred financing costs amortization and other5,371
 4,803
 —
 10,174
Working capital and other changes:       
Change in accounts receivable(85) (88,509) 99,943
 11,349
Change in inventory—
 2,559
 —
 2,559
Change in prepaid expenses(135) 1,303
 —
 1,168
Change in other current assets—
 (240) —
 (240)
Change in long-term inventory and other assets100
 (248) —
 (148)
Change in accounts payable, interest payable and accrued liabilities70,285
 (12,333) (99,943) (41,991)
Change in other current liabilities—
 (6,000) —
 (6,000)
Change in other liabilities—
 17
 —
 17
Net cash provided by (used in) operating activities(23,899) 147,318
 —
 123,419
Cash flows from investing activities:       
Capital expenditures—
 (340,314) —
 (340,314)
Proceeds from sale of properties—
 12,333
 —
 12,333
Costs related to sale of properties—
 (310) —
 (310)
Derivative settlements—
 115,576
 —
 115,576
Advances from joint interest partners—
 544
 —
 544
Net cash used in investing activities—
 (212,171) —
 (212,171)
Cash flows from financing activities:       
Proceeds from revolving credit facility—
 835,000
 —
 835,000
Principal payments on revolving credit facility—
 (778,000) —
 (778,000)
Repurchase of senior unsecured notes(435,907) —
 —
 (435,907)
Proceeds from issuance of senior unsecured convertible notes300,000
 —
 —
 300,000
Deferred financing costs(7,880) (931) —
 (8,811)
Proceeds from sale of common stock182,791
 —
 —
 182,791
Purchases of treasury stock(2,275) —
 —
 (2,275)
Investment in subsidiaries / capital contributions from parent(13,517) 13,517
 —
 —
Net cash provided by financing activities23,212
 69,586
 —
 92,798
Increase (decrease) in cash and cash equivalents(687) 4,733
 —
 4,046
Cash and cash equivalents at beginning of period777
 8,953
 —
 9,730
Cash and cash equivalents at end of period$90
 $13,686
 $—
 $13,776

17. Subsequent Events
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosuregas leases in the financial statements, other than as previously disclosed or noted below.
Derivative instruments.In October 2017,Point Arguello Unit located offshore in California. While those interests have expired, pursuant to certain related agreements (the “Point Arguello Agreements”), WOG was subject to certain abandonment and decommissioning obligations prior to WOG and Whiting rejecting the Company entered into a new swap for natural gas which settles based on Henry Hub. The commodity contract included a total notional amount of 730,000 MMBtu with a weighted average floor price of $3.07 per MMBtu which settles in 2018. This derivative instrument does not qualify for and was not designated as hedging instruments for accounting purposes.
Lease obligations.related contracts pursuant to the Whiting Plan. On October 1, 2017, the Company executed an amendment to its office space lease agreement to extend its term to March 31, 20292020, Arguello Inc. and to lease an additional 8,915 square feet of space within its current office building. This amendment increased the Company’s total future minimum rental commitments under non-cancelable leases for office space to $33.3 million. Under the terms of the amendment, the Company’s rental obligation for the new premises will begin upon occupancy of such premises for the purpose of conducting business therefrom, which is projected to be in April 2018 or earlier.
Credit facility borrowing base. On October 17, 2017, the Lenders completed their regular semi-annual redetermination of the borrowing base of the Second Amended Credit Facility, resulting in the borrowing baseFreeport-McMoRan Oil & Gas LLC, individually and the aggregate elected commitment reaffirmed at $1,600.0 million and $1,150.0 million, respectively. The next redetermination of the Company’s borrowing base is scheduled for April 1, 2018.
OMP LTIP phantom unit grant. On October 19, 2017 (the “Grant Date”), OMP granted awards under the OMP LTIP of 101,500 phantom units (collectively, the “Phantom Units,” and each a “Phantom Unit”) to certain employees of Oasis. Each Phantom Unit represents the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one OMP common unit on the day prior to the date it vests (the “Vesting Date”). Award recipients are also entitled to Distribution Equivalent Rights (a “DER”) with respect to each Phantom Unit received. Each DER represents the right to receive, upon vesting of the award, a cash payment equal to the value of the distributions paid on one OMP common unit between the Grant Date and the applicable Vesting Date. Each award of Phantom Units vests in equal amounts each year over a three-year period, and compensation expense will be recognized over the requisite service period.
Consent and Tenth Amendment to Second Amended and Restated Credit Agreement. On November 6, 2017, the Company entered into the Tenth Amendment (the “Amendment”) to the Oasis Credit Facility, pursuant to which the Lenders consented to (i) the termination of the limited recourse guaranty agreements by and between each of Beartooth DevCo LLC and Bobcat DevCo LLC (collectively, the “DevCos,” and each a “DevCo”) and Wells Fargo Bank, N.A., as administrative agent (the “Administrative Agent”), under the Oasis Credit Facility and (ii) the termination and release of each DevCo’s DevCo Mortgage (as defined in the Amendment). Further, OMS, in its capacity as the majority ownerdesignated Point Arguello Unit operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of eachcertain administrative claims arguing the FMOG Entities were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S. government through subrogation to the U.S. government’s economic rights. The FMOG Entities’ application alleged administrative claims of approximately $25 million for estimated decommissioning costs owed to the U.S. government, at least $60 million of estimated decommissioning costs owed to the FMOG Entities and claims for certain other immaterial amounts. On September 14, 2020, the FMOG Entities also filed with the Bankruptcy Court proofs of claim for rejection damages to serve as an alternative course of action in the event that a court should determine that the FMOG Entities do not hold any applicable administrative claims. The U.S. Government may also be able to bring claims against WOG directly for decommissioning costs. On February 18, 2021, WOG entered into a stipulation and agreed order with the United States Department of the DevCos, entered into the Undertaking Agreements with the Administrative Agent pursuant to which OMS agreed to limitations on the activitiesInterior, Bureau of each DevCo, including, but not limited to, the incurrence of indebtedness, asset acquisitions or dispositions, investments, mergers, issuance of additional equity interests, creation of liens on any DevCo assets or entry into any agreement that would restrict or prohibit the granting of liens on any DevCo assets, loans or advances to other persons, entry into any transaction with an affiliate, formation of a subsidiary and entry into any swap or similar derivative transactionSafety & Environmental Enforcement (the “DevCo Covenants”“BSEE”). OMS further agreed to cause corresponding amendments to the Limited Liability Company Agreement of each DevCo to implement the DevCo Covenants and to require unanimous member approval for any amendment to the DevCo Covenants.
Assignment of contract for construction of natural gas processing plant. On November 6, 2017, OMS agreed to assign to Bighorn DevCo LLC an indirect, wholly-owned subsidiary of OMP, the construction of a second gas processing plant to support Oasis’s production. Pursuant to this assignment, Bighorn DevCo LLC has agreed to assume (i) a fixed price agreement for engineering, procurement and construction of a 200 million standard cubic feet per day natural gas processing plant (the “EPC Agreement” and “Gas Plant II,” respectively), (ii) title to Gas Plant II and the ancillary equipment being constructed under the EPC Agreement, and (iii) a master service agreement and work orders pursuant to which the contractor has agreedBSEE withdrew its proofs of claims against Whiting and WOG and acknowledged their respective rights and obligations pursuant to provide mechanical refrigeration unitsthe Whiting Plan. On March 26, 2021, the FMOG Entities withdrew their administrative claim for the recovery of Whiting’s proportionate share of costs incurred after August 31, 2020 to support Gas Plant II’s operation. In addition, OMP has agreedfulfill obligations owed to reimburse OMSthe U.S. government on the basis of subrogation to the U.S. government’s economic rights. The FMOG Entities continued to assert certain other administrative claims and reserved the right to assert claims for the recovery of Whiting’s share of the decommissioning costs incurred after August 31, 2020 based on the theory of equitable subrogation. On September 14, 2021, Whiting and WOG filed an objection in the Bankruptcy Court, seeking an order partially disallowing the FMOG Entities’ claims. On October 20, 2022, the Company filed stipulations and proposed orders with the Bankruptcy Court to resolve all capital expenditures previously made underoutstanding claims asserted by the EPC Agreement or otherwise in respect of Gas Plant II. Finally,FMOG Entities. Those stipulations and proposed orders were signed by the Gas Gathering, Compression, Processing, and Gas Lift Agreement by and among OPNA, OPM, OMS, and OMP, dated as ofBankruptcy Court on October 27, 2022. Subsequent to September 25, 2017, was amended to reflect30, 2022, the Gas Plant II’s additional processing capacity. OMP currently estimates that it will reimburse OMS approximately $66.7Company paid $55.0 million in connection with Gas Plant II. cash as full and final satisfaction, discharge and release of all such claims.


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Table of Contents
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 20162021 (“20162021 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy,strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under Part“Part II, Item 1A. “RiskRisk Factors” in our 2016 Annualthis Quarterly Report on Form 10-Q could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.
Forward-looking statements may include statements about:
•crude oil, natural gas liquid (“NGL”) and natural gas realized prices;
•developments in the global economy as well as the public health crisis related to the COVID-19 pandemic and resulting demand and supply for crude oil and natural gas;
•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil and natural gas;
•war and political instability in Ukraine and the effect on commodity prices due to the ongoing conflict in Ukraine;
•general economic conditions;
•inflation rates;
•logistical challenges and supply chain disruptions;
•our business strategy;
•the geographic concentration of our operations;
•estimated future net reserves and present value thereof;
•timing and amount of future production of crude oil and natural gas;
•drilling and completion of wells;
•estimated inventory of wells remaining to be drilled and completed;
•costs of exploiting and developing our properties and conducting other operations;
•availability of drilling, completion and production equipment and materials;
•availability of qualified personnel;
owning and operating a midstream company, including ownership interests in a master limited partnership;
owning and operating a well services company;
•infrastructure for produced and flowback water gathering and disposal;
•gathering, transportation and marketing of crude oil and natural gas both in the Williston Basin and other regions in the United States;
•the possible shutdown of the Dakota Access Pipeline (“DAPL”);
•property acquisitions including our recent acquisition of oil and gas properties in the Williston Basin;divestitures;
•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;
•incurring significant transaction and other costs in connection with the Merger (as defined in the “Recent Developments” section below) in excess of those anticipated;
•failing to realize the anticipated benefits or synergies from the Merger in the timeframe expected or at all;
33
Table of Contents
•the ultimate timing, outcome and results of integrating the operations of Oasis and Whiting;
•any litigation relating to the Merger;
•the amount, nature and timing of capital expenditures;
•availability and terms of capital;
•our financial strategy,strategic tactics, budget, projections, execution of business plan and operating results;
•cash flows and liquidity;
oil•our ability to return capital to shareholders;
•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;
•our ability to comply with the covenants under our credit agreements and other indebtedness;
•operating hazards, natural gas realized prices;disasters, weather-related delays, casualty losses and other matters beyond our control;
general economic conditions;•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;
operating environment, including inclement weather conditions;•potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;
•compliance with and changes in environmental, safety and other laws and regulations;
•execution of our environmental, social and governance (“ESG”) initiatives;
•effectiveness of risk management activities;
•competition in the oil and natural gas industry;
•counterparty credit risk;
•incurring environmental liabilities;
•governmental regulation and the taxation of the oil and natural gas industry;

•developments in crude oil-producing and natural gas-producing countries;
•technology;
•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
•uncertainty regarding future operating results;
•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;
•plans, objectives, expectations and intentions contained in this report that are not historical.historical; and
•certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2021 Annual Report and in our other filings with the U.S. Securities and Exchange Commission (the “SEC”).
All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, weatherclimatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Table of Contents
Overview
We areChord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord Energy” or “Chord”) is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets in the Williston Basin. Our purpose is to improve lives by safely and responsibly providing affordable, reliable and abundant energy. We are uniquely positioned with a best-in-class balance sheet and are focused on rigorous capital discipline and generating free cash flow by operating efficiently, safely and responsibly to develop our unconventional onshore oil-rich resources in the continental United States.
Recent Developments
Return of Capital Plan
On August 3, 2022, we introduced a return of capital plan designed to provide peer-leading, sustainable shareholder returns. The return of capital plan includes a base dividend of $1.25 per share per quarter ($5.00 per share annualized) and a $300.0 million share-repurchase program. Capital will be returned through base dividends, variable dividends and share repurchases.
We expect to return a certain percentage of free cash flow (“FCF”) each quarter, with the targeted percentage based on free cash flow generated during the quarter and leverage under the following framework:
•Below 0.5x leverage:
75%+ of FCF
•Below 1.0x leverage:
50%+ of FCF
•>1.0x leverage:
Base dividend+
The Merger
On March 7, 2022, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Whiting Petroleum Corporation (“Whiting”) to combine in a merger of equals transaction (the “Merger”). Whiting was an independent oil and gas company engaged in the development, production and acquisition and development of unconventionalcrude oil, NGLs and natural gas resources primarily in the North Dakota and Montana regionsRocky Mountains region of the Williston Basin. SinceUnited States. The Merger was unanimously approved by the respective Boards of Directors of both companies, and the proposals relating to the Merger were approved by the shareholders of both companies on June 28, 2022. The Merger was completed on July 1, 2022. In connection with the completion of the Merger, we changed our inception, we have acquired properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations.name from Oasis Petroleum North America LLCInc. (“OPNA”Oasis”) conducts our domestic oilto Chord Energy.
Upon completion of the Merger on July 1, 2022, we issued 22,671,871 shares of common stock and natural gas E&P activities. We also operatepaid $245.4 million in cash to Whiting shareholders. Under the terms of the Merger Agreement, each holder of Whiting common stock, par value $0.001 per share, received 0.5774 shares of Chord common stock, par value $0.01 per share, and $6.25 per share in cash in exchange for each share of Whiting common stock.
In connection with the Merger, on June 16, 2022, the Board of Directors of Oasis declared a midstream services business through OMS Holdings LLCspecial dividend of $15.00 per share of common stock (the “Special Dividend”) that was paid on July 8, 2022 to shareholders of record as of June 29, 2022.
OMP Merger
On February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMS”OMP”) and a well services business through Oasis Well ServicesOMP GP LLC, OMP’s general partner (“OWS”OMP GP”), both of which are separate reportable business segments that are complementary to our primary development and production activities. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. We built our Williston Basin assets through acquisitions and development activities, which were financed with a combination of capital from private investors, borrowings under the senior secured revolving line of credit (the “Oasis Credit Facility”), cash flows provided by operating activities, proceeds from our senior unsecured notes, proceeds from our public equity offerings, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided an entry into a new areasubsidiary of interest or complemented our existing operations.Crestwood Equity Partners LP (“Crestwood”) and, in exchange, received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood (the “OMP Merger”). In addition,connection with the acquisitionclosing of non-operated properties in new areas provides us with geophysicalthe OMP Merger, the Company and geologic data that may leadCrestwood executed a director nomination agreement pursuant to further acquisitions in the same area, whether on an operated or non-operated basis. We intend to continue to acquire both operated and non-operated propertieswhich we designated two directors to the extentBoard of Directors of Crestwood GP Equity LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”).
On September 12, 2022, we believe they meet our return objectives.
Duesold an aggregate 16,000,000 common units of Crestwood in separate transactions and received pre-tax net proceeds of $428.2 million. On September 15, 2022, in connection with such transactions and pursuant to the geographic concentrationterms of our oilthe previously executed director nomination agreement, both directors resigned from the Board of Directors of Crestwood GP.
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Market Conditions and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:
commodity prices for oil and natural gas;
transportation capacity;
availability and cost of services; and
availability of qualified personnel.

Commodity Prices
Our revenue, profitability and future growth rateability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, NGLs and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future. Extended periodsCommodity prices increased significantly during the first half of low2022 due, in part, to disruptions to global commodity markets resulting from the Russian invasion of Ukraine, coupled with increased global economic activity as a result of fewer restrictions associated with the COVID-19 pandemic. During the third quarter of 2022, crude oil and NGL prices for oil ordecoupled from natural gas could materially and adversely affect our financial position, our results of operations, the quantities ofprices. Crude oil and NGL prices decreased in the third quarter of 2022 to levels consistent with early 2022 prior to the Russian invasion of Ukraine due to decreased consumer demand associated with slowing economic activity levels in major developed and emerging economies. Natural gas prices increased during the third quarter of 2022 due to increased liquified natural gas reserves that we can economically producedemand around the globe, particularly in Europe, stemming from lower Russian natural gas supply as a result of economic sanctions and our accessother self-sanctioning of Russian commodities due to capital.the ongoing conflict in Ukraine.
We have experienced an increase in the costs of labor, materials and services, which may continue, primarily due to continued supply chain disruptions, higher demand for services and a tight labor market. Central banks have raised interest rates in an effort to reduce inflationary pressure; however, such actions to lower inflation have slowed economic activity levels and increased the risk of a possible future economic recession.
In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. During the third quarter of 2022, our crude oil price differentials averaged a $1.63 per barrel premium to NYMEX West Texas Intermediate crude oil price index (“NYMEX WTI”). Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows.
Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. Currently, 90%wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of our gross operated oil production andSeptember 30, 2022, substantially all of our gross operated crude oil and natural gas production arewere connected to these gathering systems, and our crude oil price differentials have improved to less than $2.00 per barrel primarily due to the additional takeaway capacity of the Dakota Access Pipeline of over 450,000 barrels per day.systems.
Highlights:
We produced 66,125 barrels of oil equivalent per day (“Boepd”) in the third quarter of 2017;
We completed and placed on production 24 gross (15.1 net) operated wells in the Williston Basin in the third quarter of 2017 and ended the quarter with 82 gross operated wells waiting on completion;
Our oil differentials have improved to $1.82 off of NYMEX West Texas Intermediate crude oil index price (“WTI”) in the third quarter of 2017;
We commenced operations of our second Oasis Well Services (“OWS”) fracturing crew during the third quarter of 2017;
Oasis Midstream Partners LP (“OMP” or “Oasis Midstream”) completed its initial public offering (“IPO”) of 8,625,000 common units, which includes 1,125,000 common units issued pursuant to the underwriters’ exercise of their option on October 10, 2017. This resulted in net proceeds of approximately $137.2 million, after deducting underwriting discounts and structuring fees, of which $131.6 million was distributed to Oasis;
We announced investment in and assignment of second Wild Basin Gas Plant (“Gas Plant II”) with a total capacity of 200 million standard cubic feet per day to service gas production from its highly economic inventory;
Total capital expenditures were $240.4 million and $523.1 million for the three and nine months ended September 30, 2017, respectively. We expect full year 2017 adjusted capital expenditures to total $620.0 million, in line with prior guidance. See “Liquidity and Capital Resources” below;
At September 30, 2017, we had $8.5 million of cash and cash equivalents and had total liquidity of $953.5 million, including the availability under the Oasis Credit Facility and the OMP Operating LLC revolving line of credit (collectively, our “Revolving Credit Facilities”);
Net cash provided by operating activities was $88.9 million for the three months ended September 30, 2017. Adjusted EBITDA, a non-GAAP financial measure, was $179.6 million for the three months ended September 30, 2017. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.

Results of Operations
Comparability of Financial Statements
The results of operations presented below relate to the period ended September 30, 2022. Certain financial and operational information set forth herein does not include the activity of Whiting for periods prior to the closing of the Merger on July 1, 2022.
As of the completion of the Merger on July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. For the periods prior to July 1, 2022, we reported crude oil and natural gas, which included NGLs, on a two-stream basis. This change impacts the comparability with prior periods.
In addition, the OMP Merger qualified for reporting as a discontinued operation. Accordingly, the results of operations of OMP have been classified as discontinued operations in the Condensed Consolidated Statement of Operations for the period from January 1, 2022 to the closing of the OMP Merger on February 1, 2022. Prior periods have been recast so that the basis of presentation is consistent with that of the 2022 condensed consolidated financial statements.
Operational Highlights
•Production volumes averaged 172,481 barrels of oil equivalent per day (“Boepd”), including crude oil volumes of 96,201 barrels of oil per day (“Bopd”) in the third quarter of 2022.
•E&P capital expenditures were $224.8 million in the third quarter of 2022.
•Lease operating expense (“LOE”) was $9.86 per barrel of oil equivalent (“Boe”) in the third quarter of 2022.
•Turned-in-line 32 gross (22.5 net) operated wells in the third quarter of 2022.

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Revenues
Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our bulkrevenues for the three and nine months ended September 30, 2022 increased due to the Merger, which significantly expanded our operations in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending. Our midstream revenues are primarily derivedblending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from producedcrude oil and flowback water pipeline transport, produced and flowback water disposal, natural gas gathering and processing, fresh water sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil gathering and transportation. Our well services revenues are derived from well services, productor natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and equipment rentals. Substantially allpurchases with the same counterparty in contemplation of our midstream revenuesone another, and well services revenuesthese transactions are from services for third-party working interest owners in OPNA’s operated wells. Intercompany revenues for work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and are therefore not included in midstream and well services revenues.recorded on a net basis.
The following table summarizes our revenues, production and production dataaverage realized prices for the periods presented:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 Change 2017 2016 Change
Operating results (in thousands):           
Revenues           
Oil$221,004
 $147,095
 $73,909
 $623,603
 $411,201
 $212,402
Natural gas27,644
 9,221
 18,423
 80,930
 21,767
 59,163
Bulk oil sales21,195
 1,867
 19,328
 56,917
 1,867
 55,050
Midstream18,767
 8,487
 10,280
 48,939
 22,380
 26,559
Well services16,138
 10,641
 5,497
 33,566
 29,459
 4,107
Total revenues$304,748
 $177,311
 $127,437
 $843,955
 $486,674
 $357,281
Production data:           
Oil (MBbls)4,768
 3,628
 1,140
 13,552
 11,245
 2,307
Natural gas (MMcf)7,894
 5,007
 2,887
 23,131
 13,809
 9,322
Oil equivalents (MBoe)6,083
 4,463
 1,620
 17,408
 13,547
 3,861
Average daily production (Boepd)66,125
 48,509
 17,616
 63,764
 49,440
 14,324
Average sales prices:
 
        
Oil, without derivative settlements (per Bbl)$46.35
 $40.54
 $5.81
 $46.02
 $36.57
 $9.45
Oil, with derivative settlements (per Bbl)(1)
43.50
 43.79
 (0.29) 41.70
 46.85
 (5.15)
Natural gas (per Mcf)(2)
3.50
 1.84
 1.66
 3.50
 1.58
 1.92
Three Months Ended September 30, 2022Three Months Ended June 30, 2022Nine Months Ended September 30, 2022Nine Months Ended September 30, 2021
 
Revenues (in thousands)
Crude oil revenues$824,265 $418,860 $1,629,033 $598,278 
NGL revenues(1)
106,151 — 106,151 — 
Natural gas revenues(1)
125,730 119,707 353,031 183,181 
Purchased oil and gas sales132,697 250,489 542,653 276,349 
Other services revenues— 324 324 542 
Total revenues$1,188,843 $789,380 $2,631,192 $1,058,350 
Production data
Crude oil (MBbls)8,850 3,747 16,645 9,402 
NGLs (MBbls)(1)
3,560 — 3,560 — 
Natural gas (MMcf)(1)
20,748 12,506 46,555 32,707 
Oil equivalents (MBoe)15,868 5,831 27,964 14,853 
Average daily production (Boepd)172,481 64,079 102,432 54,407 
Average daily crude oil production (Bopd)96,201 41,174 60,971 34,440 
Average sales prices
Crude oil (per Bbl)
Average sales price$93.13 $111.79 $97.87 $63.63 
Effect of derivative settlements(2)
(19.79)(33.08)(22.76)(16.62)
Average realized price after the effect of derivative settlements(2)
$73.34 $78.71 $75.11 $47.01 
NGLs (per Bbl)(1)
Average sales price$29.82 $— $29.82 $— 
Effect of derivative settlements(2)
(0.11)— (0.11)— 
Average realized price after the effect of derivative settlements(2)
$29.71 $— $29.71 $— 
Natural gas (per Mcf)(1)
Average sales price$6.06 $9.57 $7.58 $5.60 
Effect of derivative settlements(2)
(1.67)(0.95)(1.12)(0.12)
Average realized price after the effect of derivative settlements(2)
$4.39 $8.62 $6.46 $5.48 
____________________
(1)Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for or were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)Natural gas prices include the value for natural gas and natural gas liquids.

(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting revenues, production data and average sales prices. As of July 1, 2022, NGLs were reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.
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(2)Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes. The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending in the periods presented.
Three months ended September 30, 20172022 as compared to three months ended June 30, 2022
Crude oil revenues. Our crude oil revenues increased $405.4 million to $824.3 million for the three months ended September 30, 20162022. This increase was primarily driven by a $443.7 million increase due to our expanded operations after the Merger. Excluding the impacts attributable to the Merger, our crude oil revenues decreased $38.3 million due to a decrease of $66.1 million due to lower crude oil realized prices, partially offset by an increase of $27.8 million due to higher crude oil production volumes sold quarter over quarter. Average crude oil sales prices, without derivative settlements, decreased by $18.66 per barrel quarter over quarter to an average of $93.13 per barrel for the three months ended September 30, 2022.
OilNGL revenues.As of July 1, 2022, we began reporting NGL revenues separately from natural gas revenues. This prospective change impacts the comparability of the periods presented. Our NGL revenues were $106.2 million for the three months ended September 30, 2022, including $53.5 million attributable to our expanded operations after the Merger and $52.7 million attributable to our legacy operations.
Natural gas revenues.As of July 1, 2022, we began reporting NGL revenues. separately from natural gas revenues. This prospective change impacts the comparability of the periods presented. Our oil andnatural gas revenues increased $92.3$6.0 million or 59%, to $248.6$125.7 million for the three months ended September 30, 2022 primarily driven by a $58.3 million increase due to our expanded operations after the Merger. Excluding the effects of the Merger, our natural gas revenues decreased $52.3 million, including $52.7 million due to the conversion to three-stream reporting. Stripping out the NGL component from our liquids-rich natural gas resulted in a lower price reported for residue gas during the three months ended September 30, 20172022 as compared to the three months ended SeptemberJune 30, 2016. The higher oil and2022 in which we reported revenues that included liquids-rich natural gas production amounts sold increased revenues by $62.9 million coupled with a $29.4 million increase due to the higher oil andgas. Average natural gas sales prices during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. Average oil sales prices, without derivative settlements, increaseddecreased by $5.81$3.51 per barrel to an average of $46.35 per barrel, and average natural gas sales prices, which includes the value for natural gas and natural gas liquids, increased by $1.66 perone thousand cubic feet (“Mcf”) quarter over quarter to an average of $3.50$6.06 per Mcf for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. Average daily production sold increased by 17,616 Boepd to 66,125 Boepd during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase in average daily production sold was primarily a result of our acquisition completed on December 1, 2016 of approximately 55,000 net acres in the Williston Basin (the “Williston Basin Acquisition”)2022.
Purchased oil and our 48.2 total net well completions in the Williston Basin during the twelve months ended September 30, 2017gas sales.
Bulk Purchased oil sales. Bulk oiland gas sales which represent the sale of crude oil purchased primarily for blending at our crude oil terminal that began in late 2016, increased $19.3decreased $117.8 million to $21.2$132.7 million for the three months ended September 30, 2017 as compared2022. This decrease was primarily due to lower crude oil prices quarter over quarter and a decrease in the volume of crude oil purchased and subsequently sold relative to the three months ended SeptemberJune 30, 2016.2022, when additional volumes were purchased to mitigate the impacts of production downtime associated with winter storms.
Midstream revenues. Midstream revenues increased $10.3 million to $18.8 million during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. This increase was driven by a $7.2 million increase primarily related to higher natural gas volumes gathered, compressed and processed coupled with a $2.9 million increase related to higher oil volumes gathered, stabilized and transported as a result
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Table of the start up of our natural gas processing plant and our oil gathering system in the second half of 2016, respectively.Contents
Well services revenues. Our well services revenues increased by 52% to $16.1 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016, primarily due to increased well completion product sales coupled with an increase in well completion activity as a result of adding a second fracturing fleet during the three months ended September 30, 2017.
Nine months ended September 30, 20172022 as compared to nine months ended September 30, 20162021
Oil and gas revenues. Crude oil revenues. Our crude oil and gas revenues increased $271.6$1,030.8 million or 63%, to $704.5$1,629.0 million during the nine months ended September 30, 2017 as compared tofor the nine months ended September 30, 2016. The higher oil and natural gas production amounts sold increased revenues2022. This increase was primarily driven by $138.8a $443.7 million coupled with a $132.8 million increase due to higher oil and natural gas sales prices duringour expanded operations after the nine months ended September 30, 2017 as comparedMerger. Excluding the impacts attributable to the nine months ended September 30, 2016.Merger, our crude oil revenues increased $587.1 million due to an increase of $343.3 million due to higher crude oil realized prices and $243.8 million due to higher crude oil production volumes sold period over period. Average crude oil sales prices, without derivative settlements, increased by $9.45$34.24 per barrel period over period to an average of $46.02$97.87 per barrel and average natural gas sales prices, which include the value for natural gas and natural gas liquids, increased by $1.92 per Mcf to an average of $3.50 per Mcf for the nine months ended September 30, 2017 as compared to2022.
NGL revenues. As of July 1, 2022, we began reporting NGL revenues separately from natural gas revenues. This prospective change impacts the nine months ended September 30, 2016. Average daily production sold increased by 14,324 Boepd to 63,764 Boepd period over period. The increase in average daily production sold was primarily a resultcomparability of the Williston Basin Acquisition completed on December 1, 2016 of approximately 55,000 net acres.
Bulk oil sales. Bulk oil sales increased $55.0 million to $56.9 millionfor thenine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, which represents the sale of crude oil purchased primarily for blending at our crude oil terminal that began in late 2016.
Midstreamperiods presented. Our NGL revenues. Midstream revenues increased $26.6 million to $48.9 million during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. This increase was driven by a $20.8 million increase primarily related to higher natural gas volumes gathered, compressed and processed coupled with a $7.2 million increase related to higher oil volumes gathered, stabilized and transported as a result of the start up of our natural gas processing plant and our oil gathering system in the second half of 2016, respectively. These increases were offset by a decrease of $1.5 million related to produced and flowback water disposal revenues.
Well services revenues. We increased the pace of our well completions in 2017 and added a second fracturing fleet during the third quarter of 2017. Our well services revenues increased by 14% to $33.6$106.2 million for the nine months ended September 30, 2017 as compared2022, including $53.5 million due to our expanded operations after the Merger and $52.7 million attributable to our legacy operations.
Natural gas revenues. As of July 1, 2022, we began reporting NGL revenues separately from natural gas revenues. This prospective change impacts the comparability of the periods presented. Our natural gas revenues increased $169.9 million to $353.0 million for the nine months ended September 30, 2016,2022. Excluding the effects from the Merger, our natural gas revenues increased $111.6 million primarily due to $83.1 million attributable to higher natural gas realized prices and $28.5 million attributable to higher natural gas production volumes sold period over period, partially offset by a decrease due to the conversion to three-stream reporting as of July 1, 2022. Additionally, our natural gas revenues increased period over period by $58.3 million due to our expanded operations after the Merger. Average natural gas sales prices, without derivative settlements, increased by $1.98 per Mcf period over period to an average of $7.58 per Mcf for the nine months ended September 30, 2022.
Purchased oil and gas sales. Purchased oil and gas sales increased $266.3 million to $542.7 million for the nine months ended September 30, 2022. This increase was primarily due to higher crude oil prices period over period, coupled with an increase in well completion product salescrude oil volumes purchased and well completion activity, offset by OWS completing OPNA wellsthen subsequently sold to mitigate the impacts of production downtime associated with a lower average third-party working interest period over period.winter storms in the second quarter of 2022.

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Expenses and other income (expense)
The following table summarizes our operating expenses and other income and expenses(expense) for the periods presented:
Three Months Ended September 30, 2022Three Months Ended June 30, 2022Nine Months Ended September 30, 2022Nine Months Ended September 30, 2021
 
(In thousands, except per Boe of production)
Operating expenses
Lease operating expenses$156,397 $67,722 $287,195 $146,373 
Other services expenses— 12 123 47 
Gathering, processing and transportation expenses35,549 31,813 99,759 90,920 
Purchased oil and gas expenses132,625 252,058 546,310 275,789 
Production taxes83,535 40,081 159,473 50,933 
Depreciation, depletion and amortization141,047 42,136 227,856 83,976 
Exploration and impairment910 278 1,698 1,941 
General and administrative expenses102,226 24,822 151,415 61,500 
Total operating expenses652,289 458,922 1,473,829 711,479 
Gain on sale of assets755 319 2,595 228,473 
Operating income537,309 330,777 1,159,958 575,344 
Other income (expense)
Net gain (loss) on derivative instruments337,409 (98,253)(128,766)(550,342)
Net gain (loss) from investment in unconsolidated affiliate75,093 (96,253)38,977 — 
Interest expense, net of capitalized interest(8,645)(6,949)(22,810)(23,444)
Other income (expense)(864)1,298 2,186 (793)
Total other income (expense), net402,993 (200,157)(110,413)(574,579)
Income from continuing operations before income taxes940,302 130,620 1,049,545 765 
Income tax benefit1,307 219 3,352 — 
Net income from continuing operations941,609 130,839 1,052,897 765 
Income (loss) from discontinued operations attributable to Chord, net of income tax(59,858)— 425,696 100,957 
Net income attributable to Chord$881,751 $130,839 $1,478,593 $101,722 
Costs and expenses (per Boe of production)
Lease operating expenses$9.86 $11.61 $10.27 $9.85 
Gathering, processing and transportation expenses2.24 5.46 3.57 6.12 
Production taxes5.26 6.87 5.70 3.43 
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Table of Contents
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 Change 2017 2016 Change
 (In thousands, except per Boe of production)
Operating expenses:           
Lease operating expenses$45,334
 $35,696
 $9,638
 $133,871
 $98,283
 $35,588
Midstream operating expenses4,301
 2,617
 1,684
 10,891
 6,095
 4,796
Well services operating expenses9,125
 5,548
 3,577
 21,115
 15,334
 5,781
Marketing, transportation and gathering expenses15,028
 7,003
 8,025
 38,018
 22,046
 15,972
Bulk oil purchases21,701
 1,853
 19,848
 57,683
 1,853
 55,830
Production taxes21,052
 14,638
 6,414
 60,322
 39,758
 20,564
Depreciation, depletion and amortization132,289
 111,948
 20,341
 384,246
 356,885
 27,361
Exploration expenses854
 489
 365
 4,010
 1,192
 2,818
Impairment139
 382
 (243) 6,021
 3,967
 2,054
General and administrative expenses22,531
 22,845
 (314) 69,913
 69,087
 826
Total operating expenses272,354
 203,019
 69,335
 786,090
 614,500
 171,590
Gain (loss) on sale of properties—
 6
 (6) —
 (1,305) 1,305
Operating income (loss)32,394
 (25,702) 58,096
 57,865
 (129,131) 186,996
Other income (expense)           
Net gain (loss) on derivative instruments(54,310) 20,847
 (75,157) 52,297
 (55,624) 107,921
Interest expense, net of capitalized interest(37,389) (31,726) (5,663) (110,548) (105,444) (5,104)
Gain (loss) on extinguishment of debt—
 (13,793) 13,793
 —
 4,865
 (4,865)
Other income (expense)(605) (259) (346) (755) 188
 (943)
Total other income (expense)(92,304) (24,931) (67,373) (59,006) (156,015) 97,009
Loss before income taxes(59,910) (50,633) (9,277) (1,141) (285,146) 284,005
Income tax benefit18,846
 16,691
 2,155
 470
 96,818
 (96,348)
Net loss including non-controlling interests(41,064) (33,942) (7,122) (671) (188,328) 187,657
Less: Net income attributable to non-controlling interests(2)
150
 —
 150
 150
 —
 150
Net loss attributable to Oasis$(41,214) $(33,942) $(7,272) $(821) $(188,328) $187,507
Costs and expenses (per Boe of production):           
Lease operating expenses$7.45
 $8.00
 $(0.55) $7.69
 $7.26
 $0.43
Marketing, transportation and gathering expenses(1)
2.47
 1.57
 0.90
 2.18
 1.63
 0.55
Production taxes3.46
 3.28
 0.18
 3.47
 2.93
 0.54
Depreciation, depletion and amortization21.75
 25.08
 (3.33) 22.07
 26.35
 (4.28)
General and administrative expenses3.70
 5.12
 (1.42) 4.02
 5.10
 (1.08)
____________________
(1)Prior to the first quarter of 2017, marketing, transportation and gathering expenses included bulk purchase costs related to blending at our crude oil terminal on our Condensed Consolidated Statements of Operations. Prior periods have been adjusted retrospectively to reflect these expenses in bulk oil purchases on our Condensed Consolidated Statements of Operations.
(2)As OMP completed its IPO on September 25, 2017, the net income attributable to non-controlling interests represents the interest owned by the public for the six days ended September 30, 2017.

Three months ended September 30, 20172022 as compared to three months ended SeptemberJune 30, 20162022
Lease operating expenses. Lease operating expensesexpenses. LOE increased $9.6$88.7 million to $45.3$156.4 million for the three months ended September 30, 20172022 as compared to the three months ended SeptemberJune 30, 2016. The2022 primarily due to an $85.3 million increase wasfrom our expanded operations after the Merger. Excluding the effects of the Merger, LOE increased $3.3 million primarily due to higher fixed costs associated with operating an increased number of producing wells as a result of our well completions and the Williston Basin Acquisition coupled with an increase in$4.0 million, partially offset by lower workover costs during the three months ended September 30, 2017. Lease operating expensesof $1.1 million due to fewer workover projects. LOE per Boe decreased quarter over quarter from $8.00$1.75 per Boe to $7.45 per Boe.
Midstream operating expenses. Midstream operating expenses represent operating expenses incurred by OMS associated with volumes for third-party working interest owners. The $1.7 million increase quarter over quarter was primarily related to the start up of our natural gas processing plant and our oil gathering system during 2016 coupled with an increase in freshwater purchases.
Well services operating expenses. Well services operating expenses represent operating expenses incurred by OWS for third-party working interest owners’ share of completion services. The $3.6 million increase quarter over quarter was primarily attributable to an increase in well completion product sales, maintenance and trucking costs and higher well completion activity.
Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $8.0 million, or $0.90$9.86 per Boe for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016, which was primarily attributable2022 due to higher oil gatheringproduction volumes.
Gathering, processing and transportation expenses related to the start up of the Dakota Access Pipeline in 2017expenses. Gathering, processing and the start up of our oil gathering system in the second half of 2016. In addition, natural gas gathering and processingtransportation (“GPT”) expenses increased due to additional well connections on OMS infrastructure and the start up of our natural gas processing plant in the second half of 2016. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $2.50 during the three months ended September 30, 2017 as compared to $1.58 during the three months ended September 30, 2016 primarily due to the higher aforementioned costs.
Bulk oil purchases. Bulk purchases, which represent the crude oil purchased primarily for blending at our crude oil terminal that began in late 2016, increased $19.8$3.7 million to $21.7$35.5 million for the three months ended September 30, 20172022 as compared to the three months ended SeptemberJune 30, 2016.
Production taxes. Our production taxes as a percentage of oil and natural gas sales were 8.5% and 9.4% for the three months ended September 30, 2017 and 2016, respectively. The production tax rate decreased period over period2022 primarily due to a lower oil production mix. North Dakota’s natural gas production tax is $0.0555 per Mcf.
Depreciation, depletion and amortization (“DD&A”). DD&A expense increased $20.3$2.1 million to $132.3increase from our expanded operations after the Merger, which included $9.1 million for the three months ended September 30, 2017 as comparedof GPT expenses partially offset by a $6.9 million non-cash gain attributable to the three months ended September 30, 2016. This increasechange in DD&A expense for the three months ended September 30, 2017 was a resultfair value of production increases from our wells completed during the three months ended September 30, 2017 coupled with the Williston Basin Acquisition, offset by a decreasecertain transportation derivative contracts acquired in the DD&A rateMerger for which we did not elect the “normal purchase normal sale” exclusion. See Note 7—Derivative Instruments for additional information on the transportation derivative contracts. Excluding the effects of the Merger, GPT expenses increased $1.6 million primarily due to $21.75the impact of the change in our pipeline imbalance volumes quarter over quarter. GPT expenses per Boe decreased $3.22 per Boe to $2.24 per Boe for the three months ended September 30, 20172022 due to higher production.
Purchased oil and gas expenses. Purchased oil and gas expenses decreased $119.4 million to $132.6 million for the three months ended September 30, 2022 as compared to $25.08the three months ended June 30, 2022. This decrease was primarily due to a decrease in the volume of crude oil purchased quarter over quarter where additional volumes were purchased during the three months ended June 30, 2022 to mitigate the impacts of production downtime associated with winter storms.
Production taxes. Production taxes increased $43.5 million to $83.5 million for the three months ended September 30, 2022 as compared to the three months ended June 30, 2022. This increase was primarily due to a $44.5 million increase from our expanded operations after the Merger. The production tax rate as a percentage of crude oil, NGL and natural gas sales was 7.9% for the three months ended September 30, 2022, compared to 7.4% for the three months ended June 30, 2022. This increase quarter over quarter was primarily due to an escalation of the North Dakota crude oil extraction tax of 1% effective June 1, 2022 as a result of the average price of crude oil exceeding the crude oil trigger price of $94.69 per barrel for three consecutive months. The crude oil extraction tax will be reduced by 1% if the average price of crude oil is less than the crude oil price trigger of $94.69 per barrel for three consecutive months, which we expect to occur during the fourth quarter of 2022.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expenses increased $98.9 million to $141.0 million for the three months ended September 30, 2022 as compared to the three months ended June 30, 2022. This increase was primarily due to a $74.9 million increase due to DD&A expense attributable to our expanded operations after the Merger. Excluding the effects of the Merger, depletion expense increased $24.0 million due to higher production volumes quarter over quarter and an increase in the depletion rate. The depletion rate increased $1.76 per Boe to $8.58 per Boe for the three months ended September 30, 2016. The decrease2022 due to higher costs attributable to the oil and gas properties acquired in the DD&A rate was primarily dueMerger.
General and administrative expenses. General and administrative (“G&A”) expenses increased $77.4 million to lower well costs for wells completed during the second half of 2016 and the first half of 2017.
Impairment. As a result of periodic assessments of our unproved properties not held-by-production, we recorded an impairment loss on our unproved oil and natural gas properties of $0.1 million and $0.2$102.2 million for the three months ended September 30, 2017 and 2016, respectively, related2022 as compared to acreage expiring in future periods because there were no current plansthe three months ended June 30, 2022. This increase was primarily due to drill or extend the leases prior to their expiration. Formerger-related costs of $73.4 million incurred during the three months ended September 30, 2016, we also recorded an impairment loss on our unproved oil2022. We incurred $34.9 million related to employee severance benefits, $19.1 million related to advisory, legal and natural gas propertiesother transaction-related costs and $17.8 million attributable to the acceleration of $0.2 millionequity-based compensation expenses due to leases that expired interminations of certain officers upon closing of the period. No impairment charges of proved oil and gas or other properties wereMerger.
Derivative instruments. We recorded a $337.4 million gain on derivative instruments for the three months ended September 30, 20172022, which was comprised of an unrealized gain of $554.6 million on commodity derivative contracts primarily due to a decrease in the NYMEX price curve, partially offset by a realized commodity derivative contract loss of $210.2 million and 2016.a $7.0 million loss on an embedded derivative contract that includes contingent consideration. During the three months ended June 30, 2022, we recorded a $98.3 million net loss on derivative instruments, which was comprised of a loss of $95.6 million on commodity derivative contracts and a $2.7 million loss on an embedded derivative contract that includes contingent consideration.
GeneralInvestment in unconsolidated affiliate. We recorded a $75.1 million gain related to our investment in Crestwood for the three months ended September 30, 2022, including a gain of $43.0 million attributable to our sale of 16,000,000 common units during the third quarter of 2022, a non-cash gain of $18.4 million due to an increase in the fair value of the investment and administrative expenses (“G&A”)a realized gain of $13.7 million due to a cash distribution from Crestwood in the third quarter of 2022. During the three months ended June 30, 2022, we recorded a $96.3 million net loss related to our investment in Crestwood, which was comprised of an unrealized loss of $110.0 million due to a decrease in the fair value of the investment, partially offset by a realized gain of $13.7 million due to a cash distribution from Crestwood in the second quarter of 2022. We own less than 5% of Crestwood’s issued and outstanding common units.
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Interest expense, net of capitalized interest. Our G&A decreased $0.3Interest expense increased $1.7 million to $22.5$8.6 million for the three months ended September 30, 20172022 as compared to the three months ended SeptemberJune 30, 2016. E&P G&A decreased $1.4 million quarter over quarter2022. The increase was primarily duedue to $1.8 million of bad debt expense recordedborrowings on our revolving credit facility during the three months ended September 30, 2016. OWS G&A decreased $0.3 million to $2.9 million for2022 that were subsequently repaid. There were no borrowings on our revolving credit facility during the three months ended SeptemberJune 30, 2017 as compared to the three months ended September 30, 2016. OMS G&Aincreased $1.3 million quarter over quarter primarily due to increased employee compensation expenses as a result of organizational growth due to increased activity and the start up of our natural gas processing plant in the third quarter of 2016.

Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip oil changes, we incurred a $54.3 million net loss on derivative instruments, including net cash settlement receipts of $8.1 million, for the three months ended September 30, 2017, and a $20.8 million net gain on derivative instruments, including net cash settlement receipts of $11.8 million for the three months ended September 30, 2016. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
2022. Interest expense. Interest expense increased $5.7 million from $31.7 million for the three months ended September 30, 2016 to $37.4 million for the three months ended September 30, 2017 primarily due to interest expense related to our senior unsecured convertible notes issued in September 2016, which includes debt discount amortization, and the Oasis Credit Facility coupled with a decrease in capitalized interest due to lower costs for work in progress assets as a result of the completion of our natural gas processing plant in the third quarter of 2016. These increases were offset by the repurchase of an aggregate principal amount of $447.0 million of outstanding senior unsecured notes in 2016, which resulted in a $2.1 million decrease in interest costs. For the three months ended September 30, 2017 and 2016, the weighted average debt outstanding under the Oasis Credit Facility was $484.9 million and $84.3 million, respectively. The weighted average interest rate incurred on the outstanding borrowings under the Oasis Credit Facility was 3.0% and 2.1% for the three months ended September 30, 2017 and 2016, respectively. Interest capitalized during the three months ended September 30, 20172022 and 2016June 30, 2022 was $3.1$1.3 million and $4.4$0.9 million, respectively.
Gain on extinguishment of debt. For the three months ended September 30, 2017, we did not repurchase any portion of our outstanding senior unsecured notes. During the three months ended September 30, 2016, we repurchased an aggregate principal amount of $370.4 million of our outstanding senior unsecured notes for an aggregate cost of $379.0 million, including accrued interest and fees. For the three months ended September 30, 2016, we recognized a pre-tax loss related to the repurchase of $13.8 million of our outstanding senior unsecured notes, which included unamortized deferred financing costs write-offs of $5.3 million.
Income taxes. Thetax benefit. Our income tax benefit was recorded at (0.1)% of pre-tax income from continuing operations for the three months ended September 30, 20172022 and 2016 was recorded at 31.5% and 33.0%(0.2)% of pre-tax loss, respectively. The Company’sincome from continuing operations for the three months ended June 30, 2022. Our effective tax rate for the three months ended September 30, 20172022 was lowerhigher than the effective tax rate for the three months ended June 30, 2022 primarily due to the impact of releasing a portion of the valuation allowance on our net deferred tax assets in the third quarter of 2022, coupled with the impacts of equity-based compensation windfalls.
Income (loss) from discontinued operations attributable to Chord, net of income tax. We recorded a loss from discontinued operations, net of income tax of $59.9 million for the three months ended September 30, 2016 primarily due2022. During the three months ended September 30, 2022, we recorded incremental income tax expense to discontinued operations as a result of applying the portion of OMP’s earnings allocated to the non-controlling public limited partners, which are not subject tointraperiod tax allocation rules in accordance with FASB ASC 740-20, Income Taxes – Intraperiod Tax Allocation. See Note 11—Discontinued Operations and Note 15—Income Taxes for the Company.additional information.
Nine months ended September 30, 20172022 as compared to nine months ended September 30, 20162021
Lease operating expenses. Lease operating expensesexpenses. LOE increased $35.6$140.8 million to $133.9$287.2 million for the nine months ended September 30, 20172022 as compared to the nine months ended September 30, 2016. The2021. This increase was primarily due to higher costs associated with operating an $85.3 million increase from our expanded operations after the Merger. Excluding the effects of the Merger, LOE increased number of producing wells as$55.5 million due to a result of our well completions and$67.2 million increase in the Williston Basin Acquisition coupled with an increase indue primarily to higher fixed costs of $37.7 million and higher workover costs of $21.6 million, partially offset by $11.7 million of LOE costs incurred during the nine months ended September 30, 2017. Lease operating expenses2021 in the Permian Basin on properties that were divested in June 2021. LOE per Boe increased from $7.26$0.42 per Boe to $10.27 per Boe for the nine months ended September 30, 20162022 primarily due to $7.69higher costs.
Gathering, processing and transportation expenses. GPT expenses increased $8.8 million to $99.8 million for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021. Excluding the effects of the Merger, GPT expenses increased $6.7 million primarily due to an increase of $9.3 million in the Williston Basin due primarily to higher crude oil gathering and transportation expenses of $12.3 million driven by an increase in volumes transported on DAPL, partially offset by lower natural gas gathering and processing expenses of $4.8 million. These increases were offset by $2.5 million of GPT expenses incurred during the nine months ended September 30, 2021 in the Permian Basin on properties that were divested in June 2021. Additionally, GPT expenses increased $2.1 million from our expanded operations after the Merger, which included $9.1 million of GPT expenses offset by a $6.9 million non-cash gain attributable to the change in fair value of certain transportation derivative contracts acquired in the Merger for which we did not elect the “normal purchase normal sale” exclusion. See Note 7—Derivative Instruments for additional information on the transportation derivative contracts. GPT expenses per Boe decreased $2.55 per Boe to $3.57 per Boe for the nine months ended September 30, 2017.2022 due to higher production.
Midstream operatingPurchased oil and gas expenses. Purchased oil and gas expenses. Midstream operating expenses represent operating expenses incurred by OMS associated with third-party working interest owners’ share of volumes. The $4.8 increased $270.5 million increaseto $546.3 million for the nine months ended September 30, 20172022 as compared to the nine months ended September 30, 2016 was2021 primarily relateddue to the start up of our natural gas processing plant and ourhigher crude oil gathering system during 2016.
Well services operating expenses. Well services operating expenses represent operating expenses incurred by OWS for third-party working interest owners’ share of completion services. The $5.8 million increaseprices period over period and an increase in the volume of crude oil purchased to mitigate the impacts of production downtime associated with winter storms in the second quarter of 2022.
Production taxes. Production taxes increased $108.5 million to $159.5 million for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021. This increase was primarily attributable due to a $44.5 million increase from our expanded operations after the Merger. Excluding the effects of the Merger, production taxes increased $64.1 million due to increased well completion productcrude oil sales period over period coupled with an increase in the North Dakota crude oil extraction tax of 1% effective June 1, 2022. The production tax rate as a percentage of crude oil, NGL and natural gas sales was 7.6% for the nine months ended September 30, 2022, compared to 6.5% for the nine months ended September 30, 2021. The production tax rate as a percentage of crude oil, NGL and natural gas sales increased trucking costs and increased well completion activityperiod over period primarily due to the additionimpact of lower production tax rates in the Permian Basin on properties that were divested in June 2021, coupled with the increase in the North Dakota crude oil extraction tax rate as described above.
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Depreciation, depletion and amortization. DD&A expenses increased $143.9 million to $227.9 million for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021. The increase was primarily due to a second fracturing fleet$74.9 million increase in DD&A expense attributable to our expanded operations after the Merger. Excluding the effects of the Merger, depletion expense increased $77.5 million driven by a $86.0 million increase in the Williston Basin, partially offset by $8.5 million of depletion expense incurred during the third quarter of 2017, offset by OWS completing OPNA wells with a lower average third-party working interest period over period.
Marketing, transportation and gathering expenses. Marketing, transportation and gathering expensesnine months ended September 30, 2021 in the Permian Basin on properties that were divested in June 2021. The depletion rate in the Williston Basin increased $16.0 million, or $0.55$3.19 per Boe to $7.82 per Boe for the nine months ended September 30, 20172022 due to higher costs attributable to the oil and gas properties acquired in the Merger. Fixed DD&A expense decreased $8.5 million primarily due to well service equipment that has been fully depreciated.
General and administrative expenses. G&A expenses increased $89.9 million to $151.4 million for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2016, which2021. This increase was primarily due to $82.8 million of merger-related costs, including $34.9 million of costs related to employee severance benefits, $28.2 million of advisory, legal and other transaction-related costs and $17.8 million attributable to an increase in natural gas gathering and processingthe acceleration of equity-based compensation expenses related to additional well connections on OMS infrastructure and the start up of our natural gas processing plant in the second half of 2016. In addition, oil gathering and transportation expenses increased due to the start upterminations of certain officers upon closing of the Dakota Access Pipeline in 2017 and the start upMerger.
Gain on sale of our oil gathering system in the second half of 2016. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $2.16 duringassets. For the nine months ended September 30, 2017 as compared2022, we recognized a $2.6 million gain on the sale of oil and gas properties related to $1.58 duringthe sale of certain non-core assets. For the nine months ended September 30, 2016 2021, we recognized a $228.5 million gain on sale of assets primarily related to the Permian Basin Sale.
Derivative instruments. We recorded a $128.8 million net loss on derivative instruments for the nine months ended September 30, 2022, which was comprised of a realized commodity derivative contract loss of $431.3 million, partially offset by an unrealized gain of $295.3 million on commodity derivative contracts and a $7.3 million gain on an embedded derivative contract that includes contingent consideration. During the nine months ended September 30, 2021, we recorded a $550.3 million net loss on derivative instruments which was comprised of a loss of $557.2 million on commodity derivative contracts and a $6.9 million gain on an embedded derivative contract that includes contingent consideration.
Investment in unconsolidated affiliate. We recorded a $39.0 million net gain related to our investment in Crestwood for the nine months ended September 30, 2022, including a gain of $43.0 million attributable to our sale of 16,000,000 common units during the third quarter of 2022 and a realized gain of $40.6 million due to cash distributions received from Crestwood during the higher aforementioned costs.period, offset by an unrealized loss of $44.6 million due to a decrease in the fair value of the investment. We own less than 5% of Crestwood’s issued and outstanding common units.
Bulk oil purchases. Bulk oil purchases, which represent the crude oil purchased primarily for blending at our crude oil terminal that began in late 2016, increased $55.8 million to $57.7Interest expense, net of capitalized interest. Interest expense was $22.8 million for the nine months ended September 30, 2017 as compared to2022, which was consistent with the nine months ended September 30, 2016.

Production taxes. Our production taxes as a percentage of oil and natural gas sales were 8.6% and 9.2% for the nine months ended September 30, 2017 and 2016, respectively. The production tax rate decreased period over period primarily due to a lower oil production mix. North Dakota’s natural gas production tax is $0.0555 per Mcf.
Depreciation, depletion and amortization. DD&A expense increased $27.4 million to $384.2 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. This increase in DD&A expense period over period was a result of production increases from our wells completed during the nine months ended September 30, 2017 coupled with the Williston Basin Acquisition, offset by a decrease in the DD&A rate to $22.07 per Boe for the nine months ended September 30, 2017 as compared to $26.35 per Boe for the nine months ended September 30, 2016. The decrease in the DD&A rate was primarily due to lower well costs for wells completed during the second half of 2016 and the first half of 2017.
Impairment. As a result of periodic assessments of our unproved properties not held-by-production, we recorded an impairment loss on our unproved oil and natural gas properties of $6.0 million and $0.2 million for the nine months ended September 30, 2017 and 2016, respectively, related to acreage expiring in future periods because there were no current plans to drill or extend the leases prior to their expiration. For the nine months ended September 30, 2016, we also recorded an impairment loss of $3.6 million to further adjust the carrying value of our properties held for sale to their estimated fair value, determined based on the expected sales price less costs to sell, and non-cash impairment charges of $0.2 million for unproved properties due to leases that expired during the period. No impairment charges of proved oil and gas or other properties were recorded for the nine months ended September 30, 2017.
General and administrative expenses. Our G&A increased $0.8 million to $69.9 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. OMS G&A increased $3.0 million period over period primarily due to increased employee compensation as a result of organizational growth within this segment due to the start up of our natural gas processing plant in the third quarter of 2016. OWS G&A decreased $2.0 million primarily due to OWS completing OPNA wells with a lower average third-party working interest period over period coupled with a decrease in rental expenses, offset by an increase in compensation expense due to the addition of the second fracturing fleet in the third quarter of 2017. E&P G&A was $57.8 million and $58.0 million for the nine months ended September 30, 2017 and 2016, respectively.
Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred a $52.3 million net gain on derivative instruments, including net cash settlement payments of $0.8 million, for the nine months ended September 30, 2017, and a $55.6 million net loss on derivative instruments, including net cash settlement receipts of $115.6 million, for the nine months ended September 30, 2016. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Interest expense. Interest expense increased $5.1 million from $105.4 million for the nine months ended September 30, 2016 to $110.5 million for the nine months ended September 30, 2017 primarily due to interest expense related to our senior unsecured convertible notes issued in September 2016, which includes debt discount amortization, and the Oasis Credit Facility coupled with a decrease in capitalized interest due to lower costs for work in progress assets as a result of the completion of our natural gas processing plant in the third quarter of 2016. These increases were offset by the repurchase of an aggregate principal amount of $447.0 million of outstanding senior unsecured notes in 2016, which resulted in a $16.4 million decrease in interest costs. For the nine months ended September 30, 2017 and 2016, the weighted average debt outstanding under the Oasis Credit Facility was $436.2 million and $91.2 million, respectively. The weighted average interest rate incurred on the outstanding borrowings under the Oasis Credit Facility was 2.8% and 2.0% for the nine months ended September 30, 2017 and 2016, respectively.2021. Interest capitalized during the nine months ended September 30, 20172022 and 20162021 was $8.8$2.8 million and $13.7$1.5 million, respectively.
Gain on extinguishment of debt. For the nine months ended September 30, 2017, we did not repurchase any portion of our outstanding senior unsecured notes. During the nine months ended September 30, 2016, we repurchased an aggregate principal amount of $447.0 million of our outstanding senior unsecured notes for an aggregate cost of $435.9 million, including accrued interest and fees. For the nine months ended September 30, 2016, we recognized a pre-tax gain related to the repurchase of $4.9 million, which included unamortized deferred financing costs write-offs of $6.3 million.
Income taxes. The incometax benefit. Our income tax benefit was recorded at (0.3)% of pre-tax income from continuing operations for the nine months ended September 30, 20172022 and 2016 was recorded at 41.2% and 34.0%0.0% of pre-tax loss, respectively. The Company’sincome from continuing operations for the nine months ended September 30, 2021. Our effective tax rate for the nine months ended September 30, 20172022 was higherlower than the effective tax rate for the nine months ended September 30, 20162021 primarily due to the impact of amounts expensed for book purposes versusreleasing a portion of the amounts deductible for incomevaluation allowance on our net deferred tax purposes related toassets in the third quarter of 2022, coupled with the impacts of equity-based compensation vesting at prices higher than the grant date values and non-deductible compensation, offset by the portionwindfalls.
Income (loss) from discontinued operations attributable to Chord, net of OMP’s earnings allocatedincome tax. Income from discontinued operations attributable to the non-controlling public limited partners, which are not subject toChord, net of income tax for the Company.nine months ended September 30, 2022 represents income from OMP for the period prior to the completion of the OMP Merger on February 1, 2022. We recorded income from discontinued operations attributable to Chord, net of income tax of $425.7 million for the nine months ended September 30, 2022. This was primarily comprised of a gain on sale of $518.9 million and midstream revenues of $23.3 million, offset by income tax expense of $101.1 million, midstream expenses of $13.2 million and interest expense of $3.7 million. Income from discontinued operations attributable to Chord, net of income tax was $101.0 million for the nine months ended September 30, 2021, which included midstream revenues of $183.8 million, offset by midstream expenses of $83.8 million.

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Liquidity and Capital Resources
Our primary sources of liquidity as ofduring the date ofperiod covered by this report have been proceeds from our senior unsecured notes, borrowings under our Revolving Credit Facilities, proceeds from public equity offerings, cash flows from operations, proceeds received in connection with the completion of the merger of OMP and Crestwood, proceeds received in connection with the sale of certain non-corea portion of our ownership of Crestwood common units, distributions from Crestwood for our ownership of Crestwood common units and proceeds from the exercise of outstanding warrants. Our primary uses of cash have been for cash paid to Whiting shareholders in connection with the Merger, transaction costs associated with the Merger, severance benefits paid to employees following the Merger, payment of income tax withholding obligations on vested equity awards, settlement of outstanding commodity derivative contracts, payments of dividends to shareholders, repurchases of outstanding common stock, capital expenditures for the development of oil and gas properties and cash settlementsinterest payments on our long-term debt.
In connection with the consummation of derivative contracts. Our primary usesthe Merger on July 1, 2022, we paid $245.4 million, or $6.25 per share of capitalWhiting common stock, to Whiting shareholders. In addition, we paid the Special Dividend on July 8, 2022 of $294.9 million, or $15.00 per share of common stock, to shareholders of record as of June 29, 2022.
We have incurred certain costs directly attributable to the Merger for advisory, legal, severance and other third-party fees that have been for the acquisition and development of oil and natural gas properties and midstream infrastructure, payment of operating andrecorded to general and administrative expenses on the Condensed Consolidated Statements of Operations. For the three months ended September 30, 2022, we recognized total merger-related costs of $73.4 million, including $34.9 million related to employee severance benefits, transaction costs of $19.1 million and $17.8 million related to the acceleration of unamortized stock compensation expense as a result of certain officer terminations upon completion of the Merger. For the nine months ended September 30, 2022, we recognized total merger-related costs of $82.8 million, including $34.9 million related to employee severance benefits, transaction costs of $28.2 million and $17.8 million related to the acceleration of unamortized stock compensation expense as a result of certain officer terminations upon completion of the Merger. As of September 30, 2022, we had a remaining liability of $23.3 million for the payment of employee severance benefits which was included in accrued liabilities on the Condensed Consolidated Balance Sheet. In addition, we recognized an assumed liability in connection with the Merger of $55.0 million related to outstanding claims in the Point Arguello litigation. Subsequent to September 30, 2022, we paid $55.0 million in cash as full and final satisfaction, discharge and release of all claims related to the Point Arguello litigation. See Note 19—Commitments and Contingencies for additional information.
Our material cash requirements from known obligations include repayment of outstanding borrowings and interest paymentspayment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, severance benefits payable to terminated employees and obligations associated with our operating and finance leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to shareholders through a base dividend, variable dividend and/or share repurchases. See Recent Developments—Return of Capital Plan for additional information.
We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas and water within specified time frames, the majority of which are ten years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract.
As of September 30, 2022, we had $1.5 billion of liquidity available, including $658.9 million in cash and cash equivalents and $794.1 million of aggregate unused borrowing capacity available under our revolving credit facility.
Revolving credit facility. On July 1, 2022, we entered into the Amended and Restated Credit Agreement to, among other things; (i) increase the aggregate maximum credit amount to $3.0 billion, (ii) increase the borrowing base to $2.0 billion, (iii) increase the aggregate amount of elected commitments to $800.0 million, (iv) extend the maturity date to July 1, 2027, (v) reduce the margin on outstanding debtborrowings by 125 basis points and repurchases(vi) increase the consolidated total leverage ratio financial covenant to 3.50x.
As of September 30, 2022, we had no borrowings outstanding and $5.9 million of outstanding letters of credit, resulting in an unused borrowing capacity of $794.1 million.
On October 31, 2022, we completed the semi-annual borrowing base redetermination and entered into our Second Amendment to Amended and Restated Credit Agreement to increase the aggregate amount of elected commitments to $1.0 billion and increase the borrowing base to $2.75 billion.
Senior unsecured notes. As of September 30, 2022, we have $400.0 million of 6.375% senior unsecured notes. We continually monitor potential capital sources, including equitynotes outstanding that mature on June 1, 2026. Interest on the senior unsecured notes is payable semi-annually on June 1 and debt financingsDecember 1 of each year.
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Cash Flows
The Condensed Consolidated Statements of Cash Flows have not been recast for discontinued operations, therefore the discussion below concerning cash flows from operating activities, investing activities and potential asset monetizations, in order to enhance liquidityfinancing activities includes the results of both continuing operations and decrease leverage. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.discontinued operations.
Our cash flows for the nine months ended September 30, 20172022 and 20162021 are presented below:
 Nine Months Ended September 30,
 2017 2016
 (In thousands)
Net cash provided by operating activities$298,737
 $123,419
Net cash used in investing activities(442,955) (212,171)
Net cash provided by financing activities141,480
 92,798
Increase (decrease) in cash and cash equivalents$(2,738) $4,046
Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oil and natural gas prices on a portion of our production, thereby mitigating our exposure to oil and natural gas price declines, but these transactions may also limit our cash flow in periods of rising oil and natural gas prices. For additional information on the impact of changing prices on our financial position, see Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below.
Nine Months Ended September 30,
 20222021
 (In thousands)
Net cash provided by operating activities$1,445,634 $644,746 
Net cash used in investing activities(325,699)(89,031)
Net cash provided by (used in) financing activities(635,861)272,667 
Increase in cash and cash equivalents$484,074 $828,382 
Cash flows provided by operating activities
Net cash provided by operating activities was $298.7 million and $123.4$1,445.6 million for the nine months ended September 30, 2017 and 2016, respectively.2022. The changeincrease in net cash flows fromprovided by operating activities forof $800.9 million from the periodnine months ended September 30, 2017 as compared2021 was due primarily to 2016 was primarilyhigher revenues from crude oil, NGL and natural gas sales due to higher commodity prices and our expanded operations following the resultMerger. See “Results of higheroil production amounts soldOperations” above for additional information on the impact of volumes and higher realized oil sales prices.prices on revenues and for additional information on increases and decreases in certain expenses between periods.
Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricingprices and production volumes, capital spending to fund development of our exploratoryoil and development initiatives and acquisitions,gas properties and the impactsettlement of our outstanding commodity derivative instruments. We had a working capital deficit of $99.3 million at September 30, 2017 primarily due to increases in our current liabilities, including accrued liabilities for drilling and development costs. As of September 30, 2017, we had $953.5 million of liquidity available, including $8.5 million in cash and cash equivalents and $945.0 million of unused borrowing base committed capacity available under our Revolving Credit Facilities.contracts. At September 30, 2016,2022, we had a working capital deficit of $68.3 million.

$34.8 million, compared to a working capital surplus of $60.6 million at December 31, 2021 (excluding current assets/liabilities held-for-sale). Our working capital deficit at September 30, 2022 was primarily the result of the liability position of outstanding commodity derivative contracts. We believe we have adequate liquidity to meet our working capital requirements.
Cash flows used in investing activities
Net cash used in investing activities was $443.0$325.7 million for the nine months ended September 30, 2022. The increase in net cash used in investing activities of $236.7 million from the nine months ended September 30, 2021 was primarily due to an increase of $245.0 million for cash payments to settle commodity derivative contracts, $159.9 million of capital expenditures related to the development of our oil and $212.2gas properties and a net $73.9 million related to acquisitions, which includes $245.4 million of cash paid in July 2022 to Whiting shareholders in connection with the closing of the Merger. In addition, there was a decrease of $218.2 million in proceeds from divested assets whereby we received $160.0 million in connection with the completion of the merger of OMP into Crestwood during the nine months ended September 30, 2022, while we received net proceeds from divestitures of $373.9 million during the nine months ended September 30, 2017 and 2016, respectively. Net cash used2021 primarily related to the sale of our upstream assets in investing activitiesthe Permian Basin. Additionally, we received distributions of $40.6 million during the nine months ended September 30, 2017 was primarily attributable to $443.6 million in capital expenditures primarily2022 for drilling and development costs. Netour ownership of Crestwood common units.
Cash flows provided by (used in) financing activities
Net cash used in investingfinancing activities during the nine months ended September 30, 2016 was primarily attributable to $340.3 million in capital expenditures primarily for drilling and development costs, partially offset by $115.6 million of derivative settlements received as a result of lower commodity prices and $12.3 million in proceeds received from the sale of certain legacy wells.
Our capital expenditures are summarized in the following table:
 Three Months Ended Nine Months Ended September 30, 2017
 March 31, 2017 June 30, 2017 September 30, 2017 
 (In thousands)
Capital expenditures:       
E&P$90,780
 $100,822
 $149,912
 $341,514
OMS13,144
 66,118
 79,624
 158,886
OWS—
 268
 5,142
 5,410
Other capital expenditures(1)
5,871
 5,767
 5,695
 17,333
Total capital expenditures(2)
$109,795
 $172,975
 $240,373
 $523,143
___________________
(1)Other capital expenditures include such items as administrative capital and capitalized interest.
(2)Capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.
Our total 2017 capital expenditure budget is $620.0 million, which includes $410.0 million of drilling and completion capital expenditures (including expected savings from services provided by OMS and OWS), $110.0 million for midstream infrastructure and $100.0 million of other capital expenditures, including other E&P capital, capitalized interest, OWS and administrative capital.
While we have budgeted $620.0 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Furthermore, if we acquire additional acreage, our capital expenditures may be higher than budgeted. We believe that cash on hand, including cash flows from operating activities and availability under our Revolving Credit Facilities should be sufficient to fund our 2017 capital expenditure budget and to meet our future obligations. However, because the operated wells funded by our 2017 drilling plan represent only a small percentage of our potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drilling locations should we elect to do so.
Our capital expenditures totaled $523.1$635.9 million for the nine months ended September 30, 2017,2022 was primarily attributable to dividends paid to shareholders of which $57.0$500.1 million, was reimbursedpayments of $124.8 million to repurchase common stock and payments of $36.8 million for income tax withholdings on vested equity-based compensation awards. These uses of cash were partially offset by OMP with the assignmentproceeds of Gas Plant II. Additionally, we acquired a freshwater intake facility$17.5 million from the Missouri River and a freshwater distribution system that it is expanding to service a portionexercise of the our completion activity in Wild Basin (collectively, the “Freshwater Project”). The Freshwater Project costsoutstanding warrants. Net cash provided by financing activities for the nine months ended September 30, 2017, including2021 of $272.7 million was primarily attributable to OMP’s issuance of $450.0 million in aggregate principal amount of senior notes, coupled with our issuance of $400.0 million in aggregate principal amount of senior notes. This was partially offset by the acquisition, totaled approximately $23.0 million. At the timenet principal repayments of the OMP IPO, the Freshwater Project was included in Beartooth DevCo LLC, which is 60% owned by Oasis. Excluding the Gas Plant IIoutstanding borrowings under our revolving credit facility and the Freshwater Project, ourOMP’s revolving credit facility.
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Capital Expenditures
Our capital expenditures would have(“CapEx”) from continuing operations are summarized in the following table:
Three Months EndedNine Months Ended
 March 31, 2022June 30, 2022September 30, 2022September 30, 2022
 (In thousands)
Capital expenditures
E&P$62,889 $46,005 $224,821 $333,715 
Other capital expenditures(1)
626 888 6,571 8,085 
Total E&P and other capital expenditures63,515 46,893 231,392 341,800 
Acquisitions(2,3)
— (4,779)2,364 (2,415)
Total capital expenditures(4)
$63,515 $42,114 $233,756 $339,385 
___________________
(1)Other capital expenditures includes items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $443.0$1.3 million and $2.8 million for the three and nine months ended September 30, 2022, respectively.
(2)During the three months ended June 30, 2022, the Company executed the final settlement statement with Diamondback Energy Inc. pursuant to the Company’s acquisition of approximately 95,000 net acres in the Williston Basin that was completed on October 21, 2021. Pursuant to the final settlement statement, the purchase price was reduced by $4.8 million.
(3)Excludes amounts attributable to the Merger.
(4)Total capital expenditures reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.
Dividends
Base dividends. During the nine months ended September 30, 2017, which is in line with the Company’s capital expenditure plan for2022 and 2021, we paid base dividends of $2.42 per share of common stock and $1.125 per share of common stock, respectively.
On November 2, 2022, we declared a base dividend of $1.25 per share of common stock. The dividend will be payable on November 29, 2022 to shareholders of record as of November 15, 2022.
Variable dividends. During the nine months ended September 30, 2017. Excluding the Gas Plant II and the Freshwater Project for the full year 2017capital expenditures,2022, we continue to expect adjusted capital expenditures to be approximately $620.0 million, which includes $15.0 million for activating the second fracturing spread for OWS.
Our capital budget may further be adjusted as business conditions warrant. The amount, timing and allocationpaid variable dividends of capital expenditures is largely discretionary and within our control. If oil prices decline for an extended period$5.94 per share of time, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. We actively review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Cash flowsprovided byfinancing activities
Net cash provided by financing activities was $141.5 million and $92.8 million for the nine months ended September 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017, cash provided by financing activities was primarily due to proceeds from the borrowings under our Oasis Credit Facility coupled with proceeds from the sale of OMP common units (see Note 3 – Oasis Midstream Partners LP ), net of offering costs, partially offset by principal payments on our Oasis Credit Facility. Net cash provided by financing activitiesstock. No variable dividends were paid during the nine months ended September 30, 2016 was primarily due2021.
On November 2, 2022, we declared a variable dividend of $2.42 per share of common stock. The dividend will be payable on November 29, 2022 to proceeds fromshareholders of record as of November 15, 2022.
Special dividends. In connection with the borrowings underMerger, our Oasis Credit Facility and net proceeds from the issuanceBoard of our senior unsecured convertible notes andDirectors declared a special dividend of $15.00 per share of common stock partially offset by principal payments on our Oasis Credit Facility and the repurchaseJune 16, 2022. The Special Dividend was paid on July 8, 2022 to shareholders of a portionrecord as of our outstanding senior unsecured notes. For bothJune 29, 2022.
During the nine months ended September 30, 20172021, we paid a special dividend of $4.00 per share of common stock.
See “Recent Developments—Return of Capital Plan” for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and 2016, cash was used in financing activities forcontractual restrictions applicable to the purchasespayment of treasury stock for sharesdividends and other considerations that employees surrendered backthe Board of Directors deems relevant.
Share Repurchase Program
In February 2022, the Board of Directors authorized a share-repurchase program covering up to us to pay tax withholdings upon$150.0 million of our common stock. During the vesting of restricted stock awards.
Senior secured revolving line of credit. We have the Oasis Credit Facility with an overall senior secured line of credit of $2,500.0 million as ofthree and nine months ended September 30, 2017. The Oasis Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 12022, we repurchased 1,174,756 shares of each year. The maturity date of the Oasis Credit Facility is April 13, 2020, provided that the 7.25% senior unsecured notes due February 2019 (the “2019 Notes”) are retired or refinanced 90 days prior to their maturity date. On April 10, 2017, the lenders under the Oasis Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2017, resulting in an increase in the borrowing base from $1,150.0 million to $1,600.0 million; however, we elected to limit the Lenders’ aggregate commitment to $1,150.0 million. On September 25, 2017, we entered into the ninth amendment to the Oasis Credit Facility to permit the transactions and agreements entered into in connection with the OMP IPO. On October 17, 2017, the Lenders completed their regular semi-annual redetermination of the borrowing base of the Second Amended Credit Facility, resulting in the borrowing base and the aggregate elected commitment reaffirmed at $1,600.0 million and $1,150.0 million, respectively. The next redetermination of the borrowing base is scheduled for April 1, 2018.
On November 6, 2017, we entered into the Tenth Amendment (the “Amendment”) to the Oasis Credit Facility, pursuant to which the Lenders consented to (i) the termination of the limited recourse guaranty agreements by and between each of Beartooth DevCo LLC and Bobcat DevCo LLC (collectively, the “DevCos,” and each a “DevCo”) and Wells Fargo Bank, N.A., as administrative agent (the “Administrative Agent”), under the Oasis Credit Facility and (ii) the termination and release of each DevCo’s DevCo Mortgage (as defined in the Amendment). Further, OMS, in its capacity as the majority owner of each of the DevCos, entered into the Undertaking Agreements with the Administrative Agent pursuant to which OMS agreed to limitations on the activities of each DevCo, including, but not limited to, the incurrence of indebtedness, asset acquisitions or dispositions, investments, mergers, issuance of additional equity interests, creation of liens on any DevCo assets or entry into any agreement that would restrict or prohibit the granting of liens on any DevCo assets, loans or advances to other persons, entry into any transaction with an affiliate, formation of a subsidiary and entry into any swap or similar derivative transaction (the “DevCo Covenants”). OMS further agreed to cause corresponding amendments to the Limited Liability Company Agreement of each DevCo to implement the DevCo Covenants and to require unanimous member approval for any amendment to the DevCo Covenants.
At September 30, 2017, we had $395.0 million of borrowingscommon stock at a weighted average interest rateprice of 3.0% and $10.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $745.0 million.
The Oasis Credit Facility contains covenants that include, among others:
a prohibition against incurring debt, subject to permitted exceptions;
a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
a prohibition against making investments, loans and advances, subject to permitted exceptions;
restrictions on creating liens and leases on our assets and our subsidiaries, subject to permitted exceptions;
restrictions on merging and selling assets outside the ordinary course of business;
restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
a provision limiting oil and natural gas derivative financial instruments;
a requirement that we maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility) to consolidated Interest Expense (as defined in the Oasis Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter; and

a requirement that we maintain a Current Ratio (as defined in the Oasis Credit Facility) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Oasis Credit Facility) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.
The Oasis Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Oasis Credit Facility to be immediately due and payable. We were in compliance with the financial covenants of the Oasis Credit Facility at September 30, 2017. At September 30, 2017, our consolidated EBITDAX was $602.4 million and our consolidated Interest Expense was $140.7 million, resulting in a ratio of 4.3 as compared to a minimum required ratio of 2.5. In addition, as of September 30, 2017, our consolidated current assets and consolidated current liabilities (as described above) were $1,066.8 million and $405.3 million, respectively, resulting in a Current Ratio of 2.6 as compared to a minimum required ratio of 1.0. Given the possible fluctuation in commodity prices, we continue to closely monitor our financial covenants and do not anticipate a covenant violation in the next twelve months.
OMP Operating LLC revolving line of credit. On September 25, 2017, OMP entered into a credit agreement (the “OMP Credit Agreement”)$106.25 per common share for a $200.0 million revolving credit facility with OMP Operating LLC,total cost of $124.8 million.
In August 2022, the Board of Directors authorized a subsidiary of OMP, as borrower (the “OMP Credit Facility”), which has a maturity date of September 25, 2022. The OMP Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. The borrowing capacity on the OMP Credit Facility may be increasednew share-repurchase program covering up to $400.0 million, subject to certain conditions. No amounts were outstanding under the OMP Credit Facility at September 30, 2017.
Borrowings under the OMP Credit Facility bear interest at a rate per annum equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the OMP Credit Agreement) or (ii) with respect to ABR Loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Agreement). The applicable margin for borrowings under the OMP Credit Facility varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75%, and (b) in the case of ABR Loans or swingline loans, 0.75% to 1.75%. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%.
The OMP Credit Facility requires OMP to maintain the following financial covenants as of the end of each fiscal quarter: (1) consolidated total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Facility). All obligations of OMP Operating LLC, as the borrower under the OMP Credit Facility, are guaranteed by OMP and all wholly-owned material subsidiaries of OMP. OMP Operating LLC was in compliance with the financial covenants of the OMP Credit Facility at September 30, 2017.
Senior unsecured notes. At September 30, 2017, our long-term debt includes outstanding obligations of $1,753.0 million for senior unsecured notes (the “Senior Notes”), including $54.3 million of the 2019 Notes, $395.5 million of the 6.5% senior unsecured notes due November 2021 (the “2021 Notes”), $937.1 million of the 6.875% senior unsecured notes due March 2022 (the “2022 Notes”) and $366.1 million of the 6.875% senior unsecured notes due January 2023 (the “2023 Notes”).
Prior to certain dates, we have the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par plus accrued and unpaid interest to the redemption date. We may from time to time seek to retire or purchase our outstanding Senior Notes through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
The indentures governing the Senior Notes restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when our Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants. We were in compliance with the terms of the indentures for the Senior Notes as of September 30, 2017.

Senior unsecured convertible notes. In September 2016, we issued $300.0 million of 2.625% Senior Convertible Notes due September 2023.our common stock, which resulted in the expiration of the $150.0 million share-repurchase program. We have the option to settle conversions of these notes with cash,not repurchased any shares of common stock or a combinationunder this new share-repurchase program.
See “Recent Developments—Return of cash and common stock at our election. Our intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of our common stockCapital Plan” for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding the September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, we will increase the conversion rate for a holder who elects to convert the Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of September 30, 2017, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, we were in compliance with the terms of the indentures for the Senior Convertible Notes as of September 30, 2017.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by our material subsidiaries.
Non-GAAP Financial Measures
Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP measures should not be considered in isolation or as a substitute for interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities, earnings (loss) per share or any other measures prepared under GAAP. Because Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.
Cash Interest
We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.strategy for future share repurchases.
The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented:
46
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands)
Interest expense$37,389
 $31,726
 $110,548
 $105,444
Capitalized interest3,137
 4,380
 8,773
 13,683
Amortization of deferred financing costs(1,729) (2,095) (5,128) (8,042)
Amortization of debt discount(2,591) (300) (7,426) (300)
Cash Interest$36,206
 $33,711
 $106,767
 $110,785

Adjusted EBITDA and Free Cash Flow
We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or nonrecurring charges. Adjusted EBITDA is not a measureTable of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our debt covenants.Contents
We define Free Cash Flow as Adjusted EBITDA less Cash Interest and capital expenditures, excluding capitalized interest. Free Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Free Cash Flow provides useful additional information to investors and analysts for assessing our financial performance as compared to our peers and our ability to generate cash from our business operations after interest and capital spending. In addition, Free Cash Flow excludes changes in operating assets and liabilities that relate to the timing of cash receipts and disbursements, which we may not control, and changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

The following table presents reconciliations of the GAAP financial measures of net income (loss) including non-controlling interests and net cash provided by (used in) operating activities to the non-GAAP financial measures of Adjusted EBITDA and Free Cash Flow for the periods presented:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands)
Net loss including non-controlling interests$(41,064) $(33,942) $(671) $(188,328)
(Gain) loss on sale of properties—
 (6) —
 1,305
(Gain) loss on extinguishment of debt—
 13,793
 —
 (4,865)
Net (gain) loss on derivative instruments54,310
 (20,847) (52,297) 55,624
Derivative settlements(1)
8,095
 11,786
 (804) 115,576
Interest expense, net of capitalized interest37,389
 31,726
 110,548
 105,444
Depreciation, depletion and amortization132,289
 111,948
 384,246
 356,885
Impairment139
 382
 6,021
 3,967
Exploration expenses854
 489
 4,010
 1,192
Equity-based compensation expenses6,628
 5,782
 20,451
 18,761
Income tax benefit(18,846) (16,691) (470) (96,818)
Other non-cash adjustments(208) (26) 491
 697
Adjusted EBITDA179,586
 104,394
 471,525
 369,440
Adjusted EBITDA attributable to non-controlling interests190
 —
 190
 —
Adjusted EBITDA attributable to Oasis179,396
 104,394
 471,335
 369,440
Cash Interest(36,206) (33,711) (106,767) (110,785)
Capital expenditures(2)
(240,373) (78,453) (523,143) (297,696)
Capitalized interest3,137
 4,380
 8,773
 13,683
Free Cash Flow$(94,046) $(3,390) $(149,802)
$(25,358)
     


Net cash provided by operating activities$88,876
 $32,018
 $298,737
 $123,419
Derivative settlements(1) 
8,095
 11,786
 (804) 115,576
Interest expense, net of capitalized interest37,389
 31,726
 110,548
 105,444
Exploration expenses854
 489
 4,010
 1,192
Deferred financing costs amortization and other(3,795) (3,622) (12,666) (10,174)
Changes in working capital48,375
 32,023
 71,209
 33,286
Other non-cash adjustments(208) (26) 491
 697
Adjusted EBITDA179,586
 104,394
 471,525
 369,440
Adjusted EBITDA attributable to non-controlling interests190
 —
 190
 —
Adjusted EBITDA attributable to Oasis179,396
 104,394
 471,335
 369,440
Cash Interest(36,206) (33,711) (106,767) (110,785)
Capital expenditures(2)
(240,373) (78,453) (523,143) (297,696)
Capitalized interest3,137
 4,380
 8,773
 13,683
Free Cash Flow$(94,046) $(3,390) $(149,802)
$(25,358)
___________________
(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)Capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.

The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes including non-controlling interests to the non-GAAP financial measure of Adjusted EBITDA for our three reportable business segments on a gross basis for the periods presented:
Exploration and Production
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands)
Loss before income taxes including non-controlling interests$(88,835) $(66,333) $(71,999) $(331,075)
(Gain) loss on sale of properties—
 (6) —
 1,663
(Gain) loss on extinguishment of debt—
 13,793
 —
 (4,865)
Net (gain) loss on derivative instruments54,310
 (20,847) (52,297) 55,624
Derivative settlements(1) 
8,095
 11,786
 (804) 115,576
Interest expense, net of capitalized interest37,369
 31,726
 110,528
 105,444
Depreciation, depletion and amortization129,626
 109,668
 376,818
 346,240
Impairment139
 382
 6,021
 1,536
Exploration expenses854
 489
 4,010
 1,192
Equity-based compensation expenses6,344
 5,570
 19,741
 17,495
Other non-cash adjustments(208) (26) 491
 697
Adjusted EBITDA$147,694

$86,202
 $392,509
 $309,527
___________________
(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Midstream Services
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands)
Income before income taxes including non-controlling interests$25,179
 $16,065
 $69,046
 $49,262
Gain on sale of properties—
 —
 —
 (358)
Interest expense, net of capitalized interest20
 —
 20
 —
Depreciation, depletion and amortization4,163
 1,909
 11,375
 5,325
Impairment—
 —
 —
 2,431
Equity-based compensation expenses392
 218
 1,104
 661
Adjusted EBITDA$29,754
 $18,192
 $81,545
 $57,321
Well Services
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands)
Income before income taxes including non-controlling interests$10,832
 $1,577
 $9,195
 $3,462
Depreciation, depletion and amortization3,196
 3,478
 9,417
 11,605
Equity-based compensation expenses281
 354
 1,015
 1,253
Adjusted EBITDA$14,309
 $5,409
 $19,627
 $16,320

Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share
We define Adjusted Net Income (Loss) Attributable to Oasis as net income (loss) after adjusting for (1) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash charges, or non-recurring items, (2) the impact of net income attributable to non-controlling interests and (3) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items, excluding net income attributable to non-controlling interests, in the same period. Adjusted Net Income (Loss) Attributable to Oasis is not a measure of net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share as Adjusted Net Income (Loss) Attributable to Oasis divided by diluted weighted average shares outstanding. Management believes that the presentation of Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share provides useful additional information to investors and analysts for evaluating our operational trends and performance in comparison to our peers. This measure is more comparable to earnings estimates provided by securities analysts, and charges or amounts excluded cannot be reasonably estimated and are excluded from guidance provided by the Company.
The following table presents reconciliations of the GAAP financial measure of net income (loss) attributable to Oasis to the non-GAAP financial measure of Adjusted Net Income (Loss) Attributable to Oasis and the GAAP financial measure of diluted earnings (loss) attributable to Oasis per share to the non-GAAP financial measure of Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share for the periods presented:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In thousands, except per share data)
Net loss attributable to Oasis$(41,214) $(33,942) $(821) $(188,328)
(Gain) loss on sale of properties—
 (6) —
 1,305
(Gain) loss on extinguishment of debt—
 13,793
 —
 (4,865)
Net (gain) loss on derivative instruments54,310
 (20,847) (52,297) 55,624
Derivative settlements(1)
8,095
 11,786
 (804) 115,576
Impairment139
 382
 6,021
 3,967
Amortization of deferred financing costs1,728
 2,095
 5,127
 8,042
Amortization of debt discount2,591
 300
 7,426
 300
Other non-cash adjustments(208) (26) 491
 697
Tax impact(2)
(24,941) (2,798) 12,735
 (67,598)
Adjusted Net Income (Loss) Attributable to Oasis$500

$(29,263) $(22,122) $(75,280)
 




    
Diluted loss attributable to Oasis per share$(0.18) $(0.19) $0.00
 $(1.09)
(Gain) loss on sale of properties—
 —
 —
 0.01
(Gain) loss on extinguishment of debt—
 0.08
 —
 (0.03)
Net (gain) loss on derivative instruments0.23
 (0.12) (0.22) 0.32
Derivative settlements(1)
0.03
 0.07
 —
 0.67
Impairment—
 —
 0.03
 0.02
Amortization of deferred financing costs0.01
 0.01
 0.02
 0.05
Amortization of debt discount0.01
 —
 0.03
 —
Other non-cash adjustments—
 —
 —
 —
Tax impact(2)
(0.10) (0.02) 0.05
 (0.39)
Adjusted Diluted Loss Attributable to Oasis Per Share$0.00

$(0.17) $(0.09) $(0.44)
 


    
Diluted weighted average shares outstanding233,389
 177,120
 233,248
 172,360
        
Effective tax rate applicable to adjustment items37.4% 37.4% 37.4% 37.4%
___________________
(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items.

Fair Value of Financial Instruments
See “Item 1. Financial Statements (Unaudited)—Note 6 – 6—Fair Value Measurements toMeasurements” for additional information on our unaudited condensed consolidated financial statements for a discussion of our money market funds and derivative instruments and their related fair value measurements. See also Item“Item 3. “QuantitativeQuantitative and Qualitative Disclosures Aboutabout Market Risk” below.
Critical Accounting Policies and Estimates
There have been no material changes in our critical accounting policies and estimates from those disclosed in our 20162021 Annual Report. See Note 2 – SummaryReport, except as follows.
Business combinations. We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions in the Merger relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant Accounting Policiesinputs to our unaudited condensed consolidated financial statementsthe valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of crude oil, NGL and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a discussionwilling buyer and seller would enter into in exchange for such properties. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional accounting policies and estimates made by management.information becomes known.
Item 3. — Quantitative and Qualitative Disclosures Aboutabout Market Risk
We are exposed to a variety of market risks, including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management, including the use of derivative instruments.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in prices forcrude oil, natural gasNGL and natural gas liquids,prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 20162021 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
We are exposed to a variety of market risks, including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management, including the use of derivative instruments.
Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGLs and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and other factors.the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGLs and natural gas have been volatile, especially over the last several quarters and years. These prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into commodity derivative instrumentscontracts in the past and expect to enter into derivative instruments in the futurefuture. Additionally, we may choose to cover a significant portionliquidate existing derivative positions before the contract ends in order to realize the current value of our future production.existing positions, in accordance with terms under our credit agreements.
We utilize derivative financial instrumentsIn connection with sale of our upstream assets in the Permian Basin in June 2021, we are entitled to manage risks relatedreceive up to changes in oilthree earn-out payments of $25.0 million per year for each of 2023, 2024 and natural gas prices. Our2025 if the average daily settlement price of NYMEX WTI crude oil and natural gas contracts will settle monthly based onexceeds $60 per barrel for such year. If the averageNYMEX WTI and the average NYMEX Henry Hub natural gas indexcrude oil price respectively. Asfor calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter our right to receive any remaining earn-out payments is terminated.
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Table of Contents
The fair value of our unrealized crude oil derivative positions at September 30, 2017, we utilized swaps and two-way and three-way costless collar options to reduce the volatility2022 was a net liability position of $301.6 million. A 10% increase in crude oil and natural gas prices on a significant portion of our future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor), which we will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract.
We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored intoincrease the fair value amounts recognized on the balance sheet. Derivative assets and liabilities arising from ourof this unrealized derivative contracts with the same counterparty are also reported onliability position by approximately $136.5 million, while a net basis, as all counterparty contracts provide for net settlement.

The following is a summary of our derivative contracts as of September 30, 2017:
Commodity Settlement
Period		 Derivative
Instrument		 Volumes Weighted Average Prices Fair Value
Asset (Liability)
    Swap Sub-Floor Floor Ceiling 

     

 
 (In thousands)
Crude oil 2017 Swaps 2,428,000
 Bbl $49.98
       $(3,220)
Crude oil 2017 Two-way collar 728,000
 Bbl     $46.25
 $54.37
 (576)
Crude oil 2017 Three-way collar 546,000
 Bbl   $31.67
 $45.83
 $59.94
 42
Crude oil 2018 Swaps 12,951,000
 Bbl $50.81
       (13,746)
Crude oil 2018 Two-way collar 1,250,000
 Bbl     $48.19
 $53.33
 (927)
Crude oil 2018 Three-way collar 186,000
 Bbl   $31.67
 $45.83
 $59.94
 51
Crude oil 2019 Swaps 3,423,000
 Bbl $50.83
       (846)
Crude oil 2019 Two-way collar 93,000
 Bbl     $48.67
 $53.07
 (25)
Crude oil 2020 Swaps 217,000
 Bbl $50.82
       28
Natural gas 2017 Swaps 2,024,000
 Mmbtu $3.30
       502
Natural gas 2018 Swaps 6,205,000
 Mmbtu $3.05
       (3)
                 $(18,720)
A 10% increasedecrease in crude oil prices would decrease the fair value of ourthis unrealized derivative liability position by approximately $103.8$132.7 million. The fair value of our unrealized NGL derivative positions at September 30, 2022 was a net asset of $4.9 million. A 10% increase or decrease in NGL prices would decrease or increase, respectively, the fair value of this unrealized derivative asset position by approximately $2.4 million. The fair value of our unrealized natural gas derivative positions at September 30, 2022 was a net liability of $50.1 million. A 10% increase in natural gas prices would increase the fair value of this unrealized derivative liability position by approximately $1.9 million, while a 10% decrease in crude oilnatural gas prices would increasedecrease the fair value of this unrealized derivative liability position by approximately $103.2$17.0 million. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 1. Financial Statements (Unaudited)—Note 7—Derivative Instruments” to our unaudited condensed consolidated financial statements for additional information regarding our derivative instruments.
Interest rate risk. We At September 30, 2022, we had (i) $54.3$400.0 million of senior unsecured notes at a fixed cash interest rate of 7.25%6.375% per annum, (ii) $395.5 million of senior unsecured notes at a fixed cash interest rate of 6.5% per annum, (iii) $1,303.2 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum and (iv) $300.0 million of senior unsecured convertible notes as a fixed cash interest rate of 2.625% per annum outstanding at September 30, 2017.annum. At September 30, 2017,2022, we had $395.0no borrowings and $5.9 million of borrowings and $10.0 millionoutstanding letters of credit outstandingissued under our revolving credit facility. Borrowings under the Oasis Credit Facility, which wererevolving credit facility are subject to varying rates of interest based on (1)(i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2)(ii) whether the loan is a LIBOR loanTerm SOFR Loan or a domestic bank prime interest rate loan (definedan ABR Loan (each as defined in the Oasis Credit Facility as an Alternate Based Rate or “ABR” loan)amended and restated credit agreement). At As of September 30, 2017, the2022, any outstanding borrowings under the Oasis Credit Facility boreloans would have borne interest at LIBORtheir respective interest rates plus a 1.5% margin. At September 30, 2017, no amounts were1.85% margin on any outstanding under the OMP Credit Facility. Term SOFR Loan and a 0.75% margin on any outstanding ABR Loan. The unused borrowing base capacity was subject to a commitment fee of 0.375%.
We do not currently, but may in the future, utilize interest rate derivatives to altermitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Oasis Credit Facility or the OMP Credit Facility.our revolving credit facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. No bad debt expense was recorded duringFor the three and nine months ended September 30, 2017.2022, our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to concentration of our crude oil, NGL and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.
While we do not require all ofWe monitor our customersexposure to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers forcounterparties on crude oil, NGL and natural gas receivablessales primarily by reviewing credit ratings, financial statements and the counterpartiespayment history. We extend credit terms based on our derivative instruments, we do evaluate the credit standingevaluation of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing aeach counterparty’s credit rating, latest financial information and, in the case of a customer with which weworthiness. We have receivables, their historical payment record, the financial ability of the customer’s parent companynot generally required our counterparties to make payment if the customer cannot and undertaking the due diligence necessaryprovide collateral to determine credit terms and credit limits. Several of our significant customers forsecure crude oil, NGL and natural gas sales receivables owed to us. Historically, our credit losses on crude oil, NGL and natural gas sales receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

been immaterial.
In addition, our crude oil, NGL and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions, mostinstitutions. All of the counterparties on our derivative instruments currently in place are lenders under our revolving credit facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under our revolving credit facility, which are Lenders under the Oasis Credit Facility.also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. We are likely to enter into future derivative instruments with these or other Lenders under the Oasis Credit Facility, which also carry investment grade ratings. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. We had a net derivative liability position
48
Table of $18.7 million at September 30, 2017.Contents
As permitted under our investments policy, we may purchase commercial paper instruments from high credit quality counterparties. These counterparties may include issuers in a variety of industries including the domestic and foreign financial sector. This risk is managed by our investment policy including minimum credit ratings thresholds and maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers failing to pay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If an issuer fails to repay us at maturity from commercial paper proceeds, it could take a significant amount of time to recover a portion of or all of the assets originally invested. Our commercial paper balance was $36,000 at September 30, 2017.
Item 4. — Controls and Procedures
Evaluation of disclosure controls and procedures.procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2017.2022. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that ourthe Company’s disclosure controls and procedures were effective at as of September 30, 2017.2022.
On July 1, 2022, we completed the Merger. Management’s assessment and conclusion on the effectiveness of our internal control over financial reporting as of September 30, 2022 excludes an assessment of the internal control over financial reporting of Whiting. The total assets and total revenues of Whiting represent approximately 57% and 47%, respectively, of the related consolidated financial statement amounts as of and for the three months ended September 30, 2022.
Changes in internal control over financial reporting. Therereporting
On July 1, 2022, we completed the Merger. As part of the ongoing integration, we are in the process of incorporating the controls and related procedures of Whiting. Other than incorporating Whiting’s controls, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2017third quarter of 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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Table of Contents

PART II — OTHER INFORMATION
Item 1. — Legal Proceedings
Mirada litigation.On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLCSee “Part I, Item 1. — Financial Statements (Unaudited)—Note 19—Commitments and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis Petroleum Inc., OPNA and Oasis Midstream Services LLC, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that itContingencies” which is a working interest owner in certain acreage owned and operatedincorporated herein by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area”.
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims. Discovery is ongoing, and trial is currently scheduled for July 2018. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matterreference, for a significant amount, such resolution or settlement could have adiscussion of material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin.legal proceedings.
Item 1A. — Risk Factors
Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks and uncertainties, see the information in “Part I. Item 1A. “RiskRisk Factors” in our 20162021 Annual Report. There have been no material changes in our risk factors from those described in our 20162021 Annual Report.Report, except as described below.

New climate disclosure rules proposed by the U.S. Securities and Exchange Commission may increase our costs of compliance and adversely impact our business.
On March 21, 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the proposed rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. For more information on our risks related to ESG matters and attention to climate change, see our 2021 Form 10-K risk factors “Increasing attention and federal actions in regards to Environmental, Social or Governance (“ESG”) matters may impact our business” and “Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.”
The Inflation Reduction Act could accelerate the transition to a low carbon economy and impose new costs on our operations.
On August 16, 2022, President Biden signed into law the Inflation Reduction Act (“IRA”) which, among other provisions, imposes a fee on methane emissions from sources required to report their greenhouse gas emissions to the U.S. Environmental Protection Agency, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. Beginning in 2024, the IRA’s methane emissions charge imposes a fee on excess methane emissions from certain oil and gas facilities, starting at $900 per metric ton of leaked methane in 2024 and rising to $1,200 in 2025, and $1,500 for 2026 and thereafter. The imposition of this fee and other provisions contained within the IRA could increase our operating costs and accelerate the transition away from oil and gas, which could adversely affect our business and results of operations.
Risks Relating to the Merger
We may not realize anticipated benefits and synergies expected from the Merger.
Achieving the expected benefits of the Merger depends in part on successfully consolidating the Company’s and Whiting’s functions and integrating their operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the companies’ businesses and operations. We may fail to realize the anticipated benefits and synergies expected from the Merger, which could adversely affect our business, financial condition and operating results. The Merger could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate the Company’s properties.
Achieving the expected benefits of the Merger requires, among other things, realization of the targeted synergies expected from the Merger, and there can be no assurance that we will be able to successfully integrate Whiting’s assets or otherwise realize the expected benefits of the Merger. The anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. Difficulties in integrating Whiting’s assets and operations may result in the Company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties in realizing the anticipated benefits of the Merger include:
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•disruptions of relationships with customers, distributors, suppliers, vendors, landlords and other business partners as a result of uncertainty associated with the Merger;
•difficulties integrating the Company’s business with the business of Whiting in a manner that permits us to achieve the full revenue and cost savings anticipated from the transaction;
•complexities associated with managing a larger and more complex business, including difficulty addressing possible inconsistencies in, standards, controls or operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;
•difficulties realizing anticipated synergies;
•difficulties integrating personnel, vendors and business partners;
•loss of key employees who are critical to our future operations due to uncertainty about their roles within the Company following the Merger or other concerns regarding the Merger;
•potential unknown liabilities and unforeseen expenses;
•performance shortfalls at one or more of the companies as a result of the diversion of management’s attention to integration efforts; and
•disruption of, or the loss of momentum in, the Company’s ongoing business.
We have also incurred a number of costs associated with the completion of the Merger and combining the businesses of Whiting and Chord. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the two companies, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all. Matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of management from ongoing business operations and pursuing other opportunities that could have been beneficial to us.
Our future success will depend, in part, on our ability to manage our expanded business by, among other things, integrating the assets, operations and personnel of Whiting and Chord in an efficient and timely manner; consolidating systems and management controls and successfully integrating relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition and results of operations.
The failure to integrate our businesses and operations with those of Whiting successfully in the expected time frame may adversely affect the combined business’ future results.
The Merger involved the combination of two companies that previously operated as independent public companies. It is possible that the process of integrating the two businesses following the Merger could result in the loss of key employees, the disruption of either or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities, unforeseen expenses or delays or higher-than-expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.
The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.
Following the Merger, the size of the business of the combined company increased significantly. The combined company’s future success will depend, in part, upon its ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings, revenue enhancements or other benefits currently anticipated from the Merger.
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Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds
Unregistered sales of equity securities. There were no sales of unregistered equity securities during the period covered by this report.
Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended September 30, 2017:
Period 
Total Number
of Shares
Exchanged(1)
 
Average Price
Paid
per Share
 
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
 
Maximum Number (or Approximate
Dollar Value) of Shares that May Be
Purchased Under the
Plans or Programs
July 1 - July 31, 2017 1,549
 $8.05
 —
 —
August 1 - August 31, 2017 71,779
 7.51
 —
 —
September 1 - September 30, 2017 21,076
 8.51
 —
 —
Total 94,404
 $7.74
 —
 —
2022:
Period
Total Number
of Shares
Exchanged(1)(2)
Average Price
Paid
per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)
Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs(2)
July 1 – July 31, 20221,435,349 $107.24 1,174,756 $25,155,355 
August 1 – August 31, 202214,845 128.47 — 300,000,000 
September 1 – September 30, 202210,512 136.40 — 300,000,000 
Total1,460,706 $107.67 1,174,756 
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(1)Represents shares that employees surrendered back to us to pay tax withholdings upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.
(1)The Company withheld 285,950 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.
(2)In February 2022, the Board of Directors of the Company authorized a share-repurchase program covering up to $150.0 million of the Company’s common stock. During the third quarter of 2022, the Company repurchased 1,174,756 shares of common stock at a weighted average price of $106.25 per common share for a total cost of $124.8 million. In August 2022, the Board of Directors of the Company authorized a new share-repurchase program covering up to $300.0 million of the Company’s common stock, which resulted in the expiration of the $150.0 million share-repurchase program authorized in February 2022.
Item 5. — Other Information
On November 6, 2017, weOctober 31, 2022, Chord entered into the Tenthits Second Amendment (the “Amendment”) to the OasisAmended and Restated Credit Facility, pursuant to which the Lenders consented to (i) the termination of the limited recourse guaranty agreements by and between each of Beartooth DevCo LLC and Bobcat DevCo LLC (collectively, the “DevCos,” and each a “DevCo”) and Wells Fargo Bank, N.A., as administrative agent (the “Administrative Agent”), under the Oasis Credit Facility and (ii) the termination and release of each DevCo’s DevCo Mortgage (as definedAgreement with its bank syndicate, resulting in the Amendment). Further, OMS, in its capacity asborrowing base increasing from $2.0 billion to $2.75 billion and the majority owner of each of the DevCos, entered into the Undertaking Agreements with the Administrative Agent pursuantelected commitment amount increasing from $800 million to which OMS agreed to limitations on the activities of each DevCo, including, but not limited to, the incurrence of indebtedness, asset acquisitions or dispositions, investments, mergers, issuance of additional equity interests, creation of liens on any DevCo assets or entry into any agreement that would restrict or prohibit the granting of liens on any DevCo assets, loans or advances to other persons, entry into any transaction with an affiliate, formation of a subsidiary and entry into any swap or similar derivative transaction (the “DevCo Covenants”). OMS further agreed to cause corresponding amendments to the Limited Liability Company Agreement of each DevCo to implement the DevCo Covenants and to require unanimous member approval for any amendment to the DevCo Covenants.$1 billion.
Item 6. — Exhibits
Exhibit
No.		Description of Exhibit
Exhibit
No.3.1
DescriptionCertificate of Amendment to the Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc. (incorporated by reference to Exhibit 3.2 to Chord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on July 7, 2022).
Third Amended and Restated Bylaws of Chord Energy Corporation. (incorporated by reference to Exhibit 3.3 to Chord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on July 7, 2022).
Indenture, dated as of June 9, 2021, among Chord Energy Corporation (f/k/a Oasis Petroleum Inc.), the Guarantors and Regions Bank, as trustee (incorporated by reference to Exhibit 4.1 to Chord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on June 15, 2021).
First Supplemental Indenture to Indenture dated February 7, 2022, by and among Chord Energy Corporation (f/k/a Oasis Petroleum Inc.), the Guarantors and Regions Bank, as trustee (incorporated by reference to Exhibit 4.2 to Chord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on August 12, 2022).
Second Supplemental Indenture to Indenture dated August 12, 2022, by and among Chord Energy Corporation, the Guarantors and Regions Bank, as trustee (incorporated by reference to Exhibit 4.3 to Chord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on July 7, 2022).
ContributionSeries A Warrant Agreement, dated as of September 25, 2017,1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K12B (File No. 001-31899) filed on September 1, 2020).
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Series B Warrant Agreement, dated as of September 1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Current Report on Form 8-K12B (File No. 001-31899) filed on September 1, 2020).
Warrant Assignment and Assumption Agreement, dated as of July 1, 2022, by and among Oasis Midstream Partners LP, Oasis Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLCInc., Whiting Petroleum Corporation, Computershare Inc. and OMP Operating LLC (filed asComputershare Trust Company, N.A. (incorporated by reference to Exhibit 10.110.3 to the Company'sChord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on September 29, 2017, and incorporated herein by reference)July 7, 2022).
Omnibus Agreement, dated as of September 25, 2017, by and among Oasis Midstream Partners LP, the Company, Oasis Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLC and OMP Operating LLC (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on September 29, 2017, and incorporated herein by reference).
10.3
Ninth Amendment to Second Amended and Restated Credit Agreement, dated as of September 25, 2017,July 1, 2022, by and among Oasis Petroleum Inc., Oasis Petroleum LLC, Oasis Petroleum North America LLC, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, and the lendersother parties party thereto (filed asthereto. (incorporated by reference to Exhibit 10.310.4 to the Company’sChord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on September 29, 2017, and incorporated herein by reference)July 7, 2022).
Services and Secondment Agreement, dated as of September 25, 2017, by and between Oasis Midstream Partners LP and the Company (filed as Exhibit 10.4 to the Company's Current Report on Form 8-K on September 29, 2017 and incorporated herein by reference).
10.5(a)
TenthFirst Amendment to Second Amended and Restated Credit Agreement, dated as of November 7, 2017,August 8, 2022, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto.other parties thereto (incorporated by reference to Exhibit 10.2 to Chord Energy Corporation’s Current Report on Form 8-K (File No. 001-34776) filed on August 12, 2022).

Whiting Petroleum Corporation 2020 Equity Incentive Plan (incorporated by reference to Exhibit 99.1 to Chord Energy Corporation’s Registration Statement on Form S-8 (File No. 333-266127) filed on July 14, 2022).
Second Amendment to Amended and Restated Credit Agreement, dated October 31, 2022, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties thereto.
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)XBRL Instance Document.
101.SCH(a)XBRL Schema Document.
101.CAL(a)XBRL Calculation Linkbase Document.
101.DEF(a)XBRL Definition Linkbase Document.
101.LAB(a)XBRL Labels Linkbase Document.
101.PRE(a)XBRL Presentation Linkbase Document.
___________________
(a)101.INS(a)Filed herewith.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.
(b)101.SCH(a)Furnished herewith.XBRL Schema Document.
101.CAL(a)XBRL Calculation Linkbase Document.
101.DEF(a)XBRL Definition Linkbase Document.
101.LAB(a)XBRL Label Linkbase Document.
101.PRE(a)XBRL Presentation Linkbase Document.
104(a)Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.


___________________

(a)Filed herewith.
(b)Furnished herewith.
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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.
CHORD ENERGY CORPORATION
OASIS PETROLEUM INC.
Date:November 3, 2022By:/s/ Daniel E. Brown
Date:November 8, 2017By:/s/ Thomas B. NuszDaniel E. Brown
Thomas B. Nusz
ChairmanPresident and Chief Executive Officer

(Principal Executive Officer)
By:By:/s/ Michael H. Lou
Michael H. Lou
Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)



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