UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☑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


oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☐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 001-31539
smelogohoriz4c1200204.jpg

sm-20220930_g1.jpg
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware
41-0518430
(State or other jurisdiction
of incorporation or organization)
41-0518430
(I.R.S. Employer
Identification No.)
1775 Sherman
1700 Lincoln Street, Suite 1200,3200, Denver, Colorado
80203
(Address of principal executive offices)
80203
(Zip Code)
(303) 861-8140
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbol(s)Name of each exchange on which registered
Common stock, $0.01 par valueSMNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ☑ No o☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ☑ No o☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☑Accelerated filer☐
Large accelerated filer þ
Accelerated filer o
Non-accelerated filero
(Do not check if a smaller reporting company)
☐
Smaller reporting companyo☐
Emerging growth companyo☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐ No þ☑
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
As of October 26, 2017,27, 2022, the registrant had 111,624,029122,796,046 shares of common stock $0.01 par value, outstanding.

SM ENERGY COMPANY
1

TABLE OF CONTENTS

ItemPage
Cautionary Information about Forward-Looking Statements
3
Part I
4
Part I.
FINANCIAL INFORMATION
PAGE
Item 1.
Financial Statements (Unaudited)(unaudited)
4
34
45
56
67
79
Notes to Condensed Consolidated Financial Statements
910
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
25
Item 3.
4542
Item 4.
Controls and Procedures
4542
Part II
43
Part II.
OTHER INFORMATION
Item 1.
Legal Proceedings
4643
Item 1A.
Risk Factors
4643
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
4744
Item 6.
Exhibits
4845
Signatures
46

2

Cautionary Information about Forward-Looking Statements
This Report on Form 10-Q (“Form 10-Q” or “this report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). All statements included in this report, other than statements of historical facts, that address activities, conditions, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “pending,” “plan,” “potential,” “projected,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:
•business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, debt redemptions or equity repurchases, capital markets activities, environmental, social, and governance (“ESG”) goals and initiatives, and our outlook on our future financial condition or results of operations;
•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
•our outlook on prices for future crude oil, natural gas, and natural gas liquids (also referred to throughout this report as “oil,” “gas,” and “NGLs,” respectively), well costs, service costs, production costs, and general and administrative costs;
•armed conflict, political instability, or civil unrest in crude oil and natural gas producing regions, including the ongoing conflict between Russia and Ukraine, and related potential effects on laws and regulations, or the imposition of economic or trade sanctions;
•any changes to the borrowing base or aggregate lender commitments under our Seventh Amended and Restated Credit Agreement (“Credit Agreement”);
•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;
•the effects of the global COVID-19 pandemic (“Pandemic”) on us, our industry, our financial condition, and our results of operations;
•our drilling and completion activities and other exploration and development activities, each of which could be impacted by supply chain disruptions, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;
•possible acquisitions and divestitures, including the possible divestiture or farm-out of, or farm-in or joint development of, certain properties;
•oil, gas, and NGL reserve estimates and estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates, as well as the conversion of proved undeveloped reserves to proved developed reserves;
•our expected future production volumes, identified drilling locations, as well as drilling prospects, inventories, projects and programs; and
•other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2 of this report.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors we believe are appropriate under the circumstances. We caution you that forward-looking statements are not guarantees of future performance and these statements are subject to known and unknown risks and uncertainties, which may cause our actual results or performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in the Risk Factors section in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2021 (“2021 Form 10-K”).

The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.
3

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share amounts)
data)
September 30,
2017		 December 31,
2016		September 30,
2022		December 31,
2021
ASSETS   ASSETS
Current assets:   Current assets:
Cash and cash equivalents$441,415
 $9,372
Cash and cash equivalents$498,435 $332,716 
Accounts receivable146,056
 151,950
Accounts receivable258,003 247,201 
Derivative asset63,685
 54,521
Derivative assetsDerivative assets42,207 24,095 
Prepaid expenses and other17,756
 8,799
Prepaid expenses and other9,133 9,175 
Total current assets668,912
 224,642
Total current assets807,778 613,187 
   
Property and equipment (successful efforts method):   Property and equipment (successful efforts method):
Proved oil and gas properties5,938,351
 5,700,418
Proved oil and gas properties9,914,261 9,397,407 
Less - accumulated depletion, depreciation, and amortization(3,243,072) (2,836,532)
Accumulated depletion, depreciation, and amortizationAccumulated depletion, depreciation, and amortization(6,054,796)(5,634,961)
Unproved oil and gas properties2,321,508
 2,471,947
Unproved oil and gas properties579,261 629,098 
Wells in progress287,106
 235,147
Wells in progress276,298 148,394 
Oil and gas properties held for sale, net7,144
 372,621
Other property and equipment, net of accumulated depreciation of $50,468 and $42,882, respectively106,046
 137,753
Other property and equipment, net of accumulated depreciation of $62,950 and $62,359, respectivelyOther property and equipment, net of accumulated depreciation of $62,950 and $62,359, respectively31,831 36,060 
Total property and equipment, net5,417,083
 6,081,354
Total property and equipment, net4,746,855 4,575,998 
   
Noncurrent assets:   Noncurrent assets:
Derivative asset60,035
 67,575
Derivative assetsDerivative assets36,048 239 
Other noncurrent assets32,896
 19,940
Other noncurrent assets60,832 44,553 
Total other noncurrent assets92,931
 87,515
Total Assets$6,178,926
 $6,393,511
   
LIABILITIES AND STOCKHOLDERS' EQUITY   
Total noncurrent assetsTotal noncurrent assets96,880 44,792 
Total assetsTotal assets$5,651,513 $5,233,977 
LIABILITIES AND STOCKHOLDERS’ EQUITYLIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:   Current liabilities:
Accounts payable and accrued expenses$348,885
 $299,708
Accounts payable and accrued expenses$631,984 $563,306 
Derivative liability87,791
 115,464
Derivative liabilitiesDerivative liabilities174,717 319,506 
Other current liabilitiesOther current liabilities7,316 6,515 
Total current liabilities436,676
 415,172
Total current liabilities814,017 889,327 
   
Noncurrent liabilities:   Noncurrent liabilities:
Revolving credit facility—
 —
Revolving credit facility— — 
Senior Notes, net of unamortized deferred financing costs2,768,346
 2,766,719
Senior Convertible Notes, net of unamortized discount and deferred financing costs137,012
 130,856
Asset retirement obligation100,958
 96,134
Asset retirement obligation associated with oil and gas properties held for sale—
 26,241
Senior Notes, netSenior Notes, net1,571,429 2,081,164 
Asset retirement obligationsAsset retirement obligations97,724 97,324 
Deferred income taxes208,720
 315,672
Deferred income taxes212,470 9,769 
Derivative liability67,676
 98,340
Derivative liabilitiesDerivative liabilities14,506 25,696 
Other noncurrent liabilities47,497
 47,244
Other noncurrent liabilities73,705 67,566 
Total noncurrent liabilities3,330,209
 3,481,206
Total noncurrent liabilities1,969,834 2,281,519 
   
Commitments and contingencies (note 6)

 

Commitments and contingencies (note 6)
   
Stockholders’ equity:   Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,624,029 and 111,257,500 shares, respectively1,116
 1,113
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 122,796,046 and 121,862,248 shares, respectivelyCommon stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 122,796,046 and 121,862,248 shares, respectively1,228 1,219 
Additional paid-in capital1,734,217
 1,716,556
Additional paid-in capital1,810,352 1,840,228 
Retained earnings691,915
 794,020
Retained earnings1,068,385 234,533 
Accumulated other comprehensive loss(15,207) (14,556)Accumulated other comprehensive loss(12,303)(12,849)
Total stockholders’ equity2,412,041
 2,497,133
Total stockholders’ equity2,867,662 2,063,131 
Total Liabilities and Stockholders’ Equity$6,178,926
 $6,393,511
Total liabilities and stockholders’ equityTotal liabilities and stockholders’ equity$5,651,513 $5,233,977 
The accompanying notes are an integral part of these condensed consolidated financial statements.

4


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)data)

For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,		For the Three Months Ended
September 30,		For the Nine Months Ended
September 30,
2017 2016 2017 20162022202120222021
Operating revenues and other income:       Operating revenues and other income:
Oil, gas, and NGL production revenue$294,459
 $329,165
 $912,596
 $832,130
Oil, gas, and NGL production revenue$827,558 $759,813 $2,676,656 $1,745,547 
Net gain (loss) on divestiture activity(1,895) 22,388
 (131,565) 3,413
Other operating revenues2,815
 1,107
 7,807
 2,007
Other operating incomeOther operating income7,893 426 10,673 22,387 
Total operating revenues and other income295,379

352,660

788,838

837,550
Total operating revenues and other income835,451 760,239 2,687,329 1,767,934 











Operating expenses:










Operating expenses:
Oil, gas, and NGL production expense122,651
 152,524
 385,073
 445,658
Oil, gas, and NGL production expense159,961 135,745 470,245 362,131 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion134,599
 193,966
 425,643
 619,193
Depletion, depreciation, amortization, and asset retirement obligation liability accretion145,865 202,701 460,169 574,375 
Exploration14,243
 13,482
 39,293
 41,942
Exploration14,203 8,709 44,117 26,746 
Impairment of proved properties—
 8,049
 3,806
 277,834
Abandonment and impairment of unproved properties—
 3,568
 157
 5,917
ImpairmentImpairment1,077 8,750 6,466 26,250 
General and administrative27,880
 32,679
 85,564
 93,117
General and administrative28,428 25,530 81,715 74,883 
Net derivative (gain) loss80,599
 (28,037) (89,364) 121,086
Net derivative (gain) loss(137,577)209,146 385,180 924,183 
Other operating expenses, net999
 (5,917) 6,303
 7,731
Other operating expense, netOther operating expense, net1,213 43,401 2,614 44,654 
Total operating expenses380,971

370,314

856,475

1,612,478
Total operating expenses213,170 633,982 1,450,506 2,033,222 











Loss from operations(85,592)
(17,654)
(67,637)
(774,928)











Non-operating income (expense):










Income (loss) from operationsIncome (loss) from operations622,281 126,257 1,236,823 (265,288)
Interest expense(44,091) (47,206) (135,639) (112,329)Interest expense(22,825)(40,861)(97,708)(120,268)
Gain (loss) on extinguishment of debt—
 —
 (35) 15,722
Gain (loss) on extinguishment of debt— 5 (67,605)(2,139)
Other, net1,301
 221
 2,901
 232











Loss before income taxes(128,382)
(64,639)
(200,410)
(871,303)
Income tax benefit39,270
 23,732
 65,825
 314,505











Net loss$(89,112) $(40,907) $(134,585)
$(556,798)
Other non-operating income (expense), netOther non-operating income (expense), net1,163 153 930 (1,071)
Income (loss) before income taxesIncome (loss) before income taxes600,619 85,554 1,072,440 (388,766)
Income tax (expense) benefitIncome tax (expense) benefit(119,379)39 (218,951)95 
Net income (loss)Net income (loss)$481,240 $85,593 $853,489 $(388,671)











Basic weighted-average common shares outstanding111,575
 78,468
 111,366
 71,574
Basic weighted-average common shares outstanding123,195 121,457 122,318 118,224 
Diluted weighted-average common shares outstanding111,575
 78,468
 111,366
 71,574
Diluted weighted-average common shares outstanding124,279 123,851 124,233 118,224 
Basic net loss per common share$(0.80) $(0.52) $(1.21) $(7.78)
Diluted net loss per common share$(0.80) $(0.52) $(1.21) $(7.78)
Basic net income (loss) per common shareBasic net income (loss) per common share$3.91 $0.70 $6.98 $(3.29)
Diluted net income (loss) per common shareDiluted net income (loss) per common share$3.87 $0.69 $6.87 $(3.29)
Dividends per common share$0.05
 $0.05
 $0.10
 $0.10
Dividends per common share$0.15 $0.01 $0.16 $0.02 
The accompanying notes are an integral part of these condensed consolidated financial statements.

5

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands)

 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
  
 2017 2016 2017 2016
Net loss$(89,112) $(40,907) $(134,585) $(556,798)
Other comprehensive loss, net of tax:       
Pension liability adjustment(208) (255) (651) (760)
Total other comprehensive loss, net of tax(208) (255) (651) (760)
Total comprehensive loss$(89,320) $(41,162) $(135,236) $(557,558)

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

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (UNAUDITED)
(in thousands, except share amounts)




Additional Paid-in Capital


Accumulated Other Comprehensive Loss
 Total Stockholders’ Equity

Common Stock

Retained Earnings


Shares
Amount



Balances, December 31, 2016111,257,500
 $1,113
 $1,716,556
 $794,020
 $(14,556) $2,497,133
Net loss—
 —
 —
 (134,585) —
 (134,585)
Other comprehensive loss—
 —
 —
 —
 (651) (651)
Dividends, $0.10 per share—
 —
 —
 (11,144) —
 (11,144)
Issuance of common stock under Employee Stock Purchase Plan123,678
 1
 1,737
 —
 —
 1,738
Issuance of common stock upon vesting of restricted stock units, net of shares used for tax withholdings171,278
 1
 (1,241) —
 —
 (1,240)
Stock-based compensation expense71,573
 1
 16,159
 —
 —
 16,160
Cumulative effect of accounting change (1)
—
 —
 1,108
 43,624
 —
 44,732
Other—
 —
 (102) —
 —
 (102)
Balances, September 30, 2017111,624,029
 $1,116
 $1,734,217
 $691,915
 $(15,207) $2,412,041

(1)
Refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards.

For the Three Months Ended
September 30,		For the Nine Months Ended
September 30,
2022202120222021
Net income (loss)$481,240 $85,593 $853,489 $(388,671)
Other comprehensive income, net of tax:
Pension liability adjustment182 246 546 1,029 
Total other comprehensive income, net of tax182 246 546 1,029 
Total comprehensive income (loss)$481,422 $85,839 $854,035 $(387,642)
The accompanying notes are an integral part of these condensed consolidated financial statements.

6


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)
(in thousands, except share data and dividends per share)
Additional Paid-in CapitalAccumulated Other Comprehensive LossTotal Stockholders’ Equity
Common StockRetained Earnings
SharesAmount
Balances, December 31, 2021121,862,248 $1,219 $1,840,228 $234,533 $(12,849)$2,063,131 
Net income— — — 48,764 — 48,764 
Other comprehensive income— — — — 182 182 
Cash dividends declared, $0.01 per share— — — (1,218)— (1,218)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings1,929 — (24)— — (24)
Stock-based compensation expense— — 4,274 — — 4,274 
Balances, March 31, 2022121,864,177 $1,219 $1,844,478 $282,079 $(12,667)$2,115,109 
Net income— — — 323,485 — 323,485 
Other comprehensive income— — — — 182 182 
Issuance of common stock under Employee Stock Purchase Plan65,634 1 1,644 — — 1,645 
Stock-based compensation expense29,471 — 4,479 — — 4,479 
Balances, June 30, 2022121,959,282 $1,220 $1,850,601 $605,564 $(12,485)$2,444,900 
Net income— — — 481,240 — 481,240 
Other comprehensive income— — — — 182 182 
Cash dividends declared, $0.15 per share— — — (18,419)— (18,419)
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings1,289,498 13 (25,118)— — (25,105)
Stock-based compensation expense— — 5,105 — — 5,105 
Purchase of shares under Stock Repurchase Program(452,734)(5)(20,236)— — (20,241)
Balances, September 30, 2022122,796,046 $1,228 $1,810,352 $1,068,385 $(12,303)$2,867,662 
The accompanying notes are an integral part of these condensed consolidated financial statements.
7

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued)
(in thousands, except share data and dividends per share)
Additional Paid-in CapitalAccumulated Other Comprehensive LossTotal Stockholders’ Equity
Common StockRetained Earnings (Deficit)
SharesAmount
Balances, December 31, 2020114,742,304 $1,147 $1,827,914 $200,697 $(13,598)$2,016,160 
Net loss— — — (251,269)— (251,269)
Other comprehensive income— — — — 191 191 
Cash dividends declared, $0.01 per share— — — (1,147)— (1,147)
Stock-based compensation expense— — 5,737 — — 5,737 
Balances, March 31, 2021114,742,304 $1,147 $1,833,651 $(51,719)$(13,407)$1,769,672 
Net loss— — — (222,995)— (222,995)
Other comprehensive income— — — — 592 592 
Cash dividends, $0.01 per share— — — (31)— (31)
Issuance of common stock under Employee Stock Purchase Plan252,665 3 1,312 — — 1,315 
Stock-based compensation expense57,795 1 3,955 — — 3,956 
Issuance of common stock through cashless exercise of Warrants5,918,089 59 (59)— — — 
Balances, June 30, 2021120,970,853 $1,210 $1,838,859 $(274,745)$(12,815)$1,552,509 
Net income— — — 85,593 — 85,593 
Other comprehensive income— — — — 246 246 
Cash dividends declared, $0.01 per share— — — (1,215)— (1,215)
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings502,937 5 (4,737)— — (4,732)
Stock-based compensation expense— — 4,498 — — 4,498 
Balances, September 30, 2021121,473,790 $1,215 $1,838,620 $(190,367)$(12,569)$1,636,899 
The accompanying notes are an integral part of these condensed consolidated financial statements.
8

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)

For the Nine Months Ended September 30,
20222021
Cash flows from operating activities:
Net income (loss)$853,489 $(388,671)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and asset retirement obligation liability accretion460,169 574,375 
Impairment6,466 26,250 
Stock-based compensation expense13,858 14,191 
Net derivative loss385,180 924,183 
Derivative settlement loss(595,080)(480,262)
Amortization of debt discount and deferred financing costs8,910 13,350 
Loss on extinguishment of debt67,605 2,139 
Deferred income taxes202,996 (282)
Other, net7,668 (7,301)
Net change in working capital(13,230)52,170 
Net cash provided by operating activities1,398,031 730,142 
Cash flows from investing activities:
Capital expenditures(591,846)(550,265)
Other, net(596)5,514 
Net cash used in investing activities(592,442)(544,751)
Cash flows from financing activities:
Proceeds from revolving credit facility— 1,649,500 
Repayment of revolving credit facility— (1,742,500)
Net proceeds from Senior Notes— 392,771 
Cash paid to repurchase Senior Notes(584,946)(450,776)
Repurchase of common stock(20,241)— 
Net proceeds from sale of common stock1,645 1,315 
Dividends paid(1,218)(1,178)
Other, net(35,110)(4,733)
Net cash used in financing activities(639,870)(155,601)
Net change in cash, cash equivalents, and restricted cash165,719 29,790 
Cash, cash equivalents, and restricted cash at beginning of period332,716 10 
Cash, cash equivalents, and restricted cash at end of period$498,435 $29,800 
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest$(125,668)$(126,228)
Investing activities:
Increase in capital expenditure accruals and other$50,590 $8,885 
Non-cash financing activities (1)

 For the Nine Months Ended 
 September 30,
 2017 2016
Cash flows from operating activities:   
Net loss$(134,585) $(556,798)
Adjustments to reconcile net loss to net cash provided by operating activities:   
Net (gain) loss on divestiture activity131,565
 (3,413)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion425,643
 619,193
Impairment of proved properties3,806
 277,834
Abandonment and impairment of unproved properties157
 5,917
Stock-based compensation expense16,160
 20,485
Net derivative (gain) loss(89,364) 121,086
Derivative settlement gain29,402
 306,234
Amortization of debt discount and deferred financing costs12,478
 5,687
Non-cash (gain) loss on extinguishment of debt, net22
 (15,722)
Deferred income taxes(67,458) (314,770)
Plugging and abandonment(2,095) (5,222)
Other, net4,713
 (8,857)
Changes in current assets and liabilities:   
Accounts receivable21,502
 1,221
Prepaid expenses and other(8,955) 7,652
Accounts payable and accrued expenses21,560
 (65,166)
Accrued derivative settlements6,046
 19,651
Net cash provided by operating activities370,597
 415,012
    
Cash flows from investing activities:   
Net proceeds from the sale of oil and gas properties778,365
 201,829
Capital expenditures(624,969) (492,794)
Acquisition of proved and unproved oil and gas properties(87,389) (21,853)
Acquisition deposit held in escrow3,000
 (49,000)
Net cash provided by (used in) investing activities69,007
 (361,818)
    
Cash flows from financing activities:   
Proceeds from credit facility406,000
 743,000
Repayment of credit facility(406,000) (945,000)
Debt issuance costs related to credit facility—
 (3,132)
Net proceeds from Senior Notes—
 492,397
Cash paid to repurchase Senior Notes(2,344) (29,904)
Net proceeds from Senior Convertible Notes—
 166,681
Cash paid for capped call transactions—
 (24,109)
Net proceeds from sale of common stock1,738
 533,266
Dividends paid(5,563) (3,404)
Other, net(1,392) (2,341)
Net cash provided by (used in) financing activities(7,561) 927,454
    
Net change in cash and cash equivalents432,043
 980,648
Cash and cash equivalents at beginning of period9,372
 18
Cash and cash equivalents at end of period$441,415
 $980,666

(1)    Please refer to Note 5 - Long-Term Debt for discussion of the debt transactions executed during the nine months ended September 30, 2022, and 2021.
The accompanying notes are an integral part of these condensed consolidated financial statements.

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)
(in thousands)

Supplemental schedule of additional cash flow information and non-cash activities:
9
 For the Nine Months Ended 
 September 30,
 2017 2016
Supplemental Cash Flow Information:   
Operating Activities:   
Cash paid for interest, net of capitalized interest (1)
$(124,443) $(88,109)
Net cash (paid) refunded for income taxes$(2,800) $4,481
Investing Activities:   
Changes in capital expenditure accruals and other$2,788
 $(1,287)
    
Supplemental Non-Cash Investing Activities:   
Value of properties exchanged$283,651
 $733
    
Supplemental Non-Cash Financing Activities:   
Dividends declared, but not paid$5,581
 $4,343

(1)

Cash paid for interest, net of capitalized interest for the nine months ended September 30, 2016, does not include the $10.0 million paid to terminate a second lien facility that was no longer necessary to fund acquisition activity.

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

SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 - The Company and BusinessSummary of Significant Accounting Policies

Description of Operations
SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report)NGLs in onshore North America.

Note 2 - Basisthe state of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards

Texas.
Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and its wholly-owned subsidiariesthe Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in SM Energy’s Annual Report onthe 2021 Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of September 30, 2017,2022, and through the filing of this report. CertainAdditionally, certain prior period amounts have been reclassified to conform to the current period presentation onin the accompanying unaudited condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies to in the Company’s consolidated financial statements in its 20162021 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the 20162021 Form 10-K.

10-K.
Recently Issued Accounting Standards

Effective January 1, 2017,In September 2022, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”)issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718)2022-04, Liabilities - Supplier Finance Programs (Subtopic 405-50): Improvements to Employee Share-Based Payment AccountingDisclosure of Supplier Finance Program Obligations (“ASU 2016-09”2022-04”). ASU 2016-092022-04 was issued to enhance the transparency of supplier finance programs and implement explicit GAAP disclosure requirements for those programs. The guidance is meant to simplify certain aspects of accountingbe applied retrospectively to each period in which a balance sheet is presented, except for share-based arrangements,the amendment on rollforward information, which is to be applied prospectively. ASU 2022-04 is effective for fiscal years beginning after December 15, 2022, including income tax effects, accountinginterim periods within those fiscal years, except for forfeitures, and net share settlements.the amendment on rollforward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company adoptedis evaluating the various applicable amendments, which are summarized as follows:
On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Additionally, going forward excess tax benefits will be presented in operating activities on the condensed consolidated statement of cash flows.
Also on January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in additional paid-in capital of $1.1 million, a decrease in deferred tax assets of $0.4 million, and a net $0.7 million cumulative effect adjustment decrease to retained earnings.
Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between periods. Please refer to Note 4 - Income Taxes for additional discussion.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several amendments to the standard which provided additional implementation guidance and deferred the effective date of ASU 2022-04 on its disclosures.

2014-09. Based upon work performed asAs of September 30, 2017,2022, and through the filing of this report, the Company does not currently anticipate a material impact to net income (loss) or cash flows. Further, the Company completed its initial assessment of certain pipeline gathering, transportation and gas processing agreements, and does not anticipate changes in how total revenues or total expenses will be recognized given where control transfers for these agreements. In addition, the Company is in the process of implementing appropriate changes to its business processes, systems, and controls to support the recognition and disclosure requirements of ASU 2014-09. The Company plans to adopt the guidance using the modified retrospective method on the effective date of January 1, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires lessees to recognize a right-of-use asset and a lease liability for virtually all leases currently classified as operating leases. The Company is currently analyzing the impact this standard will have on the Company’s contract portfolio, including non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements, and other existing arrangements. Further, the Company is evaluating current accounting policies, applicable systems, controls, and processes to support the potential recognition and disclosure changes resulting from ASU 2016-02. Based upon an initial assessment, adoption of ASU 2016-02 is expected to result in an increase in assets and liabilities recorded. The Company plans to adopt the guidance on the effective date of January 1, 2019.

In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company plans to adopt ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost in the consolidated statements of operations and prospective application for the capitalization of the service cost component of net benefit costs in assets. While ASU 2017-07 will result in the Company reclassifying certain amounts from operating expenses to non-operating expenses upon adoption, the Company does not currently anticipate ASU 2017-07 will result in a material impact to the Company’s consolidated financial statements or disclosures.

Other than as disclosed above or in the 2016 Form 10-K, there are no other ASUs have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of September 30, 2017, and through the filing of this report.disclosures.

Note 2 - Revenue from Contracts with Customers
Note 3 - Divestitures, Assets Held for Sale, and Acquisitions
Divestitures

On March 10, 2017,the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $747.4 million. The Company finalized this divestiture subsequent to September 30, 2017,recognizes its share of revenue from the sale of produced oil, gas, and recorded a final net gainNGLs from its Midland Basin and South Texas assets. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of $396.8 million foroperations (“accompanying statements of operations”) is reflective of the nine months ended September 30, 2017. These assets were classified as held for sale as of December 31, 2016.revenue generated from contracts with customers.

10

The following table presents income (loss) before income taxes fromtables below present oil, gas, and NGL production revenue by product type for each of the outside-operated Eagle Ford shale assets soldCompany’s operating areas for the three and nine months ended September 30, 2017,2022, and 2016. This divestiture is considered a disposal of a significant asset group.2021:
Midland BasinSouth TexasTotal
Three Months Ended
September 30,		Three Months Ended
September 30,		Three Months Ended
September 30,
202220212022202120222021
(in thousands)
Oil production revenue$420,838$501,071$105,095$57,323$525,933$558,394
Gas production revenue123,91296,082110,64152,878234,553148,960
NGL production revenue31510366,75752,35667,07252,459
Total$545,065$597,256$282,493$162,557$827,558$759,813
Relative percentage66 %79 %34 %21 %100 %100 %
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in thousands)
Income (loss) before income taxes (1)
$—
 $22,116
 $24,324
 $(251,451)

(1)
Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes included impairment of proved properties expense of approximately $269.6 million for the nine months ended September 30, 2016.

Midland BasinSouth TexasTotal
Nine Months Ended
September 30,		Nine Months Ended
September 30,		Nine Months Ended
September 30,
202220212022202120222021
(in thousands)
Oil production revenue$1,449,660$1,191,668$350,594$108,871$1,800,254$1,300,539
Gas production revenue363,728205,323282,201121,630645,929326,953
NGL production revenue597315229,876117,740230,473118,055
Total$1,813,985$1,397,306$862,671$348,241$2,676,656$1,745,547
Relative percentage68 %80 %32 %20 %100 %100 %
During the first nine months of 2017,the Company divested certain non-core properties in its Rocky Mountain and Permian regions for net divestiture proceeds of $31.0 million.


During the third quarter of 2016, the Company divested certain non-core properties in its Rocky Mountain and Permian regions for net divestiture proceeds of $165.2 million. As of September 30, 2016, $23.6 million of accrued costs and payments to Net Profits Plan participants related to divestitures were included in accounts payable and accrued expenses in the Company’s condensed consolidated balance sheets. The Company recorded a $22.4 million net gain on divestiture activity for the three months ended September 30, 2016, which was a result of closing divestitures in the Company’s Rocky Mountainrecognizes oil, gas, and Permian regions during the third quarter of 2016. Certain of these sold assets were written down in the first quarter of 2016 and subsequently written up in the second quarter of 2016 based on changes in the estimated fair value less selling costs, resulting in a net gain of $6.3 million recorded for the nine months ended September 30, 2016.

Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and it is probable the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. When assets no longer meet the criteria of assets held for sale, they are measuredNGL production revenue at the lowerpoint in time when custody and title (“control”) of the carrying valueproduct transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control drives the assets before being classified as held for sale, adjusted for any depletion, depreciation,presentation of transportation, gathering, processing, and amortization expense that would have been recognized, orother post-production expenses (“fees and other deductions”) within the fair value at the date they are reclassified to assets held for use. Any gain or loss recognized on assets held for sale or on assets held for sale that are subsequently reclassified to assets held for use is reflected in the net gain (loss) on divestiture activity line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).operations. Fees and other deductions incurred by the Company prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred at or near the wellhead, sales are based on a wellhead market price that is impacted by fees and other deductions incurred by the purchaser subsequent to the transfer of control. Please refer to Note 2 - Revenue from Contracts with Customers in the 2021 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL production revenue is generated.
Significant judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to purchasers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day, therefore there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of September 30, 2017, there were $7.1 million of assets heldproduction delivered to the customer and the consideration that will ultimately be received for sale presented inof the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”). until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of September 30, 2022, and December 31, 2021, were $220.0 million and $215.6 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser.

11

Note 3 - Equity
Stock Repurchase Program
On September 7, 2022, the Company announced that its Board of Directors approved a stock repurchase program authorizing the Company to repurchase up to $500.0 million in aggregate value of its common stock through December 31, 2024 (“Stock Repurchase Program”). The Stock Repurchase Program permits the Company to repurchase shares of its common stock from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of the Credit Agreement and the indentures governing the Senior Notes, as defined in Note 5 - Long-Term Debt. The Company intends to fund repurchases from available working capital and cash provided by operating activities. Stock repurchases may also be funded with borrowings under the Credit Agreement. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by the Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of its shares will be repurchased by the Company. The Stock Repurchase Program terminates and supersedes the August 1998 authorization to repurchase common stock, under which 3,072,184 shares remained available for repurchase prior to termination.
During the three months ended September 30, 2022, the Company repurchased and subsequently retired 452,734 shares of its common stock at a weighted-average share price of $44.69 for a total cost of $20.2 million, excluding commissions and fees. As of September 30, 2022, $479.8 million remained available for repurchases of the Company’s outstanding common stock under the Stock Repurchase Program.
Warrants
On June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its then outstanding common stock, at an exercise price of $0.01 per share (“Warrants”). The Warrants became exercisable at the election of the holders on January 15, 2021, pursuant to the terms of the Warrant Agreement, dated June 17, 2020 (“Warrant Agreement”). The Warrants are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement, if exercised.
Upon issuance, the $21.5 million fair value of the Warrants was recorded in additional paid-in capital on the accompanying balance sheets, and was determined using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). The Company evaluated the Warrants under authoritative accounting guidance and determined that they should be classified as equity instruments, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the Warrants since issuance.
No Warrants were exercised during the nine months ended September 30, 2017, the Company recorded a $526.5 million write-down on its retained Divide County, North Dakota, assets previously held for sale, of which $359.6 million was recorded in the first quarter of 2017 based on an estimated fair value less selling costs and an additional $166.9 million write-down was recorded in2022. During the second quarter of 2017 based on market conditions that existed on the date2021, the Company decided to retain the assets.

Acquisitions

During the first nine monthsissued 5,918,089 shares of 2017, the Company acquired approximately 3,400 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $72.2 million of cash consideration. Under authoritative accounting guidance, these transactions were considered asset acquisitions and the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired.

The Company finalized the 2016 acquisition of Midland Basin properties from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”) during the first quarter of 2017 by paying an additional $7.4 million of cash consideration, resulting in total consideration of approximately $1.0 billion paid after final closing adjustments. The Company finalized the 2016 acquisition of Midland Basin properties from QStar LLC and RRP-QStar, LLC (referred to as the “QStar Acquisition”) during the third quarter of 2017 by paying an additional $7.3 million of cash consideration, with the majority of this payment being made in the first quarter of 2017, resulting in total consideration of approximately $1.6 billion paid after final closing adjustments. The Company funded these acquisitions with proceeds from divestitures, the Senior Convertible Notes issuance, the issuance of 6.75% Senior Notes due 2026 (“2026 Notes”), and equity offerings in 2016. Please refer to Note 5 - Long-Term Debt and Note 15 - Equity in the Company’s 2016 Form 10-K for more information on the funding for these acquisitions. There were no material changes to the initial recorded basis of these proved and unproved properties acquiredcommon stock as a result of the final settlements.

Also, duringcashless exercise of 5,922,260 Warrants at a weighted-average share price of $15.45 per share, as determined under the first nine monthsterms of 2017, the Company completed several non-monetary acreage tradesWarrant Agreement. At the request of primarily unproved properties, in Howardstockholders and Martin Counties, Texas, resulting in the Company acquiring approximately 7,425 net acres in exchange for approximately 6,725 net acres with $283.7 million of value attributedpursuant to the properties assigned byCompany’s obligations under the CompanyWarrant Agreement, a registration statement covering the resale of a majority of these shares was filed with the U.S. Securities and Exchange Commission (“SEC”) on June 11, 2021.
Dividends
During the third quarter of 2022, the Company’s Board of Directors approved an increase to the Company’s fixed dividend to $0.60 per share annually, to be paid in such trades. These trades were recordedquarterly increments of $0.15 per share. During the three months ended September 30, 2022, cash dividends declared totaled $18.4 million, and will be paid on November 7, 2022, to stockholders of record at carryover basis with no gain or loss recognized.the close of business on October 25, 2022.

12


Note 4 - Income Taxes

The provision for income tax benefit recordedtaxes for the three and nine months ended September 30, 2017,2022, and 2016,2021, consists of the following:
For the Three Months Ended
September 30,		For the Nine Months Ended
September 30,
2022202120222021
(in thousands)
Current portion of income tax expense:
Federal$(7,014)$— $(11,287)$—
State(2,317)(29)(4,668)(187)
Deferred portion of income tax (expense) benefit(110,048)68 (202,996)282
Income tax (expense) benefit$(119,379)$39 $(218,951)$95
Effective tax rate19.9 %— %20.4 %— %
Recorded income tax expense or benefit differs from the amountsamount that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxestaxes. These differences primarily duerelate to the effect of state income taxes, excess tax benefits and deficiencies from share-based paymentstock-based compensation awards, state income taxes,tax deduction limitations on the compensation of covered individuals, changes in valuation allowances, and accumulated impactsthe cumulative effect of other smaller permanent differences.differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balances. The quarterly rate and the resulting income tax (expense) benefit can also be affected by the proportional impactseffects of forecastedforecast net income or loss as ofand the correlative effect on the valuation allowance for each period end presented.

The provision forpresented, as reflected in the table above. Forecast net income taxeshad a larger impact on the effective tax rate for the three and nine months ended September 30, 2017,2022, compared with the same periods in 2021, and 2016, consisted ofvaluation allowance adjustments had a larger impact on the following:
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in thousands)
Current portion of income tax benefit (expense):       
Federal$2,832
 $—
 $—
 $—
State(230) (24) (1,633) (265)
Deferred portion of income tax benefit36,668
 23,756
 67,458
 314,770
Income tax benefit$39,270
 $23,732
 $65,825
 $314,505
Effective tax rate30.6% 36.7% 32.8% 36.1%

On a year-to-date basis, a change in the Company’s effective tax rate between reportingfor the three and nine months ended September 30, 2021, compared with the same periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in2022.
For all years before 2019, the composition of income or loss from Company activities among multiple state tax jurisdictions. Cumulative effects of state tax rate changes are reflected in the period legislation is enacted. As a result of adopting ASU 2016-09 on January 1, 2017, excess tax benefits and deficiencies from share-based payment awards impact the Company’s effective tax rate between periods. As discussed in Note 7 - Compensation Plans, the Company settled various grants in the third quarter of 2017. As a result of these share-based award settlements, the Company recorded an $8.2 million excess tax deficiency in the third quarter of 2017 reducing the tax benefit and the tax benefit rate.

At the end of the third quarter 2017, the Company reevaluated various factors affecting deferred tax assets related to net operating losses and tax credits, and determined utilization would be appropriate. The change in the current portion of income tax benefit (expense) between periods reflects the effect of this determination. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013. Its 2003 to 2005 tax years have been reopened for net operating loss carryback claims and are currently under examination by the Internal Revenue Service (the “IRS”). During the quarter ended September 30, 2017, the Company received a $5.5 million refund in advance of the IRS completing its examination of the Company’s claims.authorities.

Note 5 - Long-Term Debt

Credit Agreement

The Company’s FifthOn August 2, 2022, the Company entered into a Seventh Amended and Restated Credit Agreement by and among the Company, Wells Fargo Bank, National Association, as amended (the “Credit Agreement”Administrative Agent and Swingline Lender (“Agent”), and the institutions named therein as lenders. The Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion, an initial borrowing base of $2.5 billion, and has a maturity dateinitial aggregate lender commitments totaling $1.25 billion. As of December 10, 2019. On March 31, 2017, the Company entered into a Ninth Amendment to the Credit Agreement (the “Ninth Amendment”) with its lenders. Pursuant to the Ninth Amendment, and as part of the regular, semi-annual borrowing base redetermination process,September 30, 2022, the borrowing base and aggregate lender commitments were reduced to $925 million primarily due tounder the sale of the Company’s outside-operated Eagle Ford shale assets and the decrease in the valueCredit Agreement remained unchanged. The revolving credit facility is secured by substantially all of the Company’s proved reserves at December 31, 2016.oil and gas properties. The borrowing base is subject to regular, semi-annual redetermination, processand considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve reportreport; and (b) commodity derivative contracts, each as determined by the Company’s lender group. AsThe next scheduled borrowing base redetermination date is April 1, 2023. The Credit Agreement is scheduled to mature on the earlier of (a) August 2, 2027 (“Stated Maturity Date”), or (b) 91 days prior to the maturity date of any of the filingCompany’s outstanding Senior Notes, as defined below, to the extent that, on or before such date, the respective Senior Notes have not been repaid, exchanged, repurchased, refinanced, or otherwise redeemed in full, and, if refinanced or exchanged, with a scheduled maturity date that is not earlier than at least 180 days after the Stated Maturity Date.
In addition to other terms, conditions, agreements, and provisions, the Credit Agreement establishes the Secured Overnight Financing Rate (“SOFR”) as the benchmark for determining interest rates in replacement of this report, the second semi-annual redeterminationLondon Interbank Offered Rate (“LIBOR”). LIBOR was discontinued as a global reference rate for 2017 was in progressnew loans and is expected to be completed prior to year-end.

contracts after December 31, 2021. The Company must comply with certain financial and non-financial covenants under the terms ofCredit Agreement require, among other customary covenants, that the Company’s (a) total funded debt, as defined by the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 3.50 to 1.00 on the last day of each fiscal quarter; and was(b) adjusted current ratio, as defined in compliance with all such covenantsthe Credit Agreement, cannot be less than 1.00 to 1.00 as of September 30, 2017, and through the filinglast day of this report.any fiscal quarter.

Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement, andas presented in Note 5 - Long-Term Debt tothe table below. At the Company’s consolidated financial statementselection, borrowings under the Credit Agreement may be in its 2016 Form 10-K.  Eurodollarthe form of SOFR, Alternate Base Rate (“ABR”), or Swingline loans. SOFR loans accrue interest at the London Interbank Offered Rate,SOFR plus the applicable margin from the utilization table,grid, and Alternate Base Rate

ABR and swinglineSwingline loans accrue interest at the primea market-based floating rate, plus the
13

applicable margin from the utilization table.grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount and are included in interest expense inat rates from the accompanying statements of operations.utilization grid.

Borrowing Base Utilization Percentage<25%≥25% <50%≥50% <75%≥75% <90%≥90%
SOFR Loans2.000 %2.250 %2.500 %2.750 %3.000 %
ABR Loans or Swingline Loans1.000 %1.250 %1.500 %1.750 %2.000 %
Commitment Fee Rate0.375 %0.375 %0.500 %0.500 %0.500 %
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of October 26, 2017,27, 2022, September 30, 2017,2022, and December 31, 2016:2021:
As of October 27, 2022As of September 30, 2022As of December 31, 2021
As of October 26, 2017 As of September 30, 2017 As of December 31, 2016
(in thousands)(in thousands)
Credit facility balance (1)
$—
 $—
 $—
Revolving credit facility (1)
Revolving credit facility (1)
$— $— $— 
Letters of credit (2)
200
 200
 200
Letters of credit (2)
6,000 6,000 2,500 
Available borrowing capacity924,800
 924,800
 1,164,800
Available borrowing capacity1,244,000 1,244,000 1,097,500 
Total aggregate lender commitment amount$925,000
 $925,000
 $1,165,000
Total aggregate lender commitment amount$1,250,000 $1,250,000 $1,100,000 

(1)    Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $11.4 million and $2.7 million as of September 30, 2022, and December 31, 2021, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis.
(2)    Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.
Senior Secured Notes
On June 17, 2022, the Company redeemed all of the $446.7 million of aggregate principal amount outstanding of its 10.0% Senior Secured Notes due 2025 (“2025 Senior Secured Notes” or “Senior Secured Notes”). The 2025 Senior Secured Notes were redeemed with cash on hand, at a redemption price equal to 107.5 percent of the principal amount outstanding on the date of the redemption, plus accrued and unpaid interest. Upon redemption, the Company recorded a net loss on extinguishment of debt of $67.2 million which included $33.5 million of premium paid, $26.3 million of accelerated unamortized debt discount, and $7.4 million of accelerated unamortized deferred financing costs. The Company canceled all redeemed 2025 Senior Secured Notes upon settlement.
The 1.50% Senior Secured Convertible Notes due 2021 (“2021 Senior Secured Convertible Notes”) matured on July 1, 2021, and on that day, the Company used borrowings under its revolving credit facility to retire at par the outstanding principal amount of $65.5 million. Interest expense recognized on the 2021 Senior Secured Convertible Notes related to the stated interest rate and amortization of the debt discount. No interest expense was recognized for the three months ended September 30, 2021, and $2.3 million of interest expense was recognized for the nine months ended September 30, 2021.
Senior Secured Notes, net of unamortized discount and deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets, as of December 31, 2021, consist of the following:
(1)
As of December 31, 2021
(in thousands)
Principal amount of 10.0% Senior Secured Notes due 2025$446,675 
Unamortized debt discount30,236 
Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $3.5 million and $5.9 million as of September 30, 2017, and December 31, 2016, respectively.
8,727 
(2)
10.0% Senior Secured Notes due 2025, net of unamortized debt discount and deferred financing costs		Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.$407,712 
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Senior Unsecured Notes
The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). The SeniorUnsecured Notes, net of unamortized deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of September 30, 2017, 2022, and December 31, 2016, consisted2021, consist of the following:following (collectively referred to as “Senior Unsecured Notes,” and together with the 2025 Senior Secured Notes, “Senior Notes”):
 As of September 30, 2017 As of December 31, 2016
 Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs
 (in thousands)
6.50% Senior Notes due 2021 (1) (2)
$344,611
 $2,830
 $341,781
 $346,955
 $3,372
 $343,583
6.125% Senior Notes due 2022 (2)
561,796
 6,095
 555,701
 561,796
 6,979
 554,817
6.50% Senior Notes due 2023 (2)
394,985
 3,889
 391,096
 394,985
 4,436
 390,549
5.0% Senior Notes due 2024500,000
 5,841
 494,159
 500,000
 6,533
 493,467
5.625% Senior Notes due 2025500,000
 6,940
 493,060
 500,000
 7,619
 492,381
6.75% Senior Notes due 2026 (3)
500,000
 7,451
 492,549
 500,000
 8,078
 491,922
Total$2,801,392
 $33,046
 $2,768,346
 $2,803,736
 $37,017
 $2,766,719

(1)
During the first quarter of 2017, the Company repurchased a total of $2.3 million in aggregate principal amount of 6.50% Senior Notes due 2021 in open market transactions at a slight premium. The Company canceled all of these repurchased Senior Notes upon cash settlement.
(2)
During the first quarter of 2016, the Company repurchased a total of $46.3 million in aggregate principal amount of certain of its Senior Notes in open market transactions for a settlement amount of $29.9 million, excluding interest. The Company recorded a net gain on extinguishment of debt of approximately $15.7 million for the nine months ended September 30, 2016. This amount includes a gain of approximately $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. The Company canceled all of these repurchased Senior Notes upon cash settlement.
(3)
On September 12, 2016, the Company issued 6.75% Senior Notes due September 15, 2026. The Company received net proceeds of $491.6 million after deducting paid and accrued fees. The net proceeds were used to partially fund the Rock Oil Acquisition that closed on October 4, 2016.


As of September 30, 2022As of December 31, 2021
Principal AmountUnamortized Deferred Financing CostsPrincipal Amount, NetPrincipal AmountUnamortized Deferred Financing CostsPrincipal Amount, Net
(in thousands)
5.0% Senior Notes due 2024$— $— $— $104,769 $403 $104,366 
5.625% Senior Notes due 2025349,118 1,686 347,432 349,118 2,160346,958 
6.75% Senior Notes due 2026419,235 2,744 416,491 419,235 3,270415,965 
6.625% Senior Notes due 2027416,791 3,366 413,425 416,791 3,949412,842 
6.5% Senior Notes due 2028400,000 5,919 394,081 400,000 6,679 393,321 
Total$1,585,144 $13,715 $1,571,429 $1,689,913 $16,461 $1,673,452 
The Senior Unsecured Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes.  The Company is subject to certain covenants under the indentures governing the Senior Notes and was in compliance with all such covenants as of September 30, 2017, and through the filing of this report. The Company may redeem some or all of its Senior Unsecured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Unsecured Notes.

Senior Convertible Notes

On August 12, 2016,February 14, 2022, the Company redeemed all of the $104.8 million of aggregate principal amount outstanding of its 5.0% Senior Notes due 2024 (“2024 Senior Notes”), with cash on hand, pursuant to the terms of the indenture governing the 2024 Senior Notes which provided for a redemption price equal to 100 percent of the principal amount of the 2024 Senior Notes on the date of redemption, plus accrued and unpaid interest. The Company canceled all redeemed 2024 Senior Notes upon settlement.
On June 23, 2021, the Company issued $172.5$400.0 million in aggregate principal amount of 1.50%its 6.5% Senior Convertible Notes dueat par with a maturity date of July 1, 2021 (the “Senior Convertible15, 2028 (“2028 Senior Notes”). The Senior Convertible NotesCompany received net proceeds of $392.8 million after deducting fees of $7.2 million, which are unsecured senior obligations and rank equal in right of payment with allbeing amortized as deferred financing costs over the life of the Company’s existing2028 Senior Notes. The net proceeds were used to repurchase $193.1 million and any future unsecured senior debt, and are senior in right$172.3 million of payment to any future subordinated debt.

The Senior Convertible Notes mature on July 1, 2021, unless earlier converted. Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under certain circumstances as outlined in the indenture governing the Senior Convertible Notes and in Note 5 – Long-Term Debt to the Company’s consolidated financial statements in its 2016 Form 10-K. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000outstanding principal amount of the Company’s 6.125% Senior Convertible Notes due 2022 (“2022 Senior Notes”) and 2024 Senior Notes, respectively, through a cash tender offer (“Tender Offer”), and to redeem the remaining $19.3 million of 2022 Senior Notes not repurchased as part of the Tender Offer (“2022 Senior Notes Redemption”). The Company paid total consideration, excluding accrued interest, of $385.3 million, and recorded a net loss on extinguishment of debt of $2.1 million for the three months ended June 30, 2021, which is equalincluded $1.5 million of accelerated unamortized deferred financing costs and $0.6 million of net premiums. The Company canceled all repurchased and redeemed 2022 Senior Notes and 2024 Senior Notes upon settlement.
Please refer to an initial conversion price of approximately $40.50 per share,Note 5 - Long-Term Debt in the 2021 Form 10-K for additional detail on the Company’s Senior Notes.
Covenants
As discussed above, the Company is subject to adjustment.
certain financial and non-financial covenants under the Credit Agreement and under the indentures governing the Senior Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted payments including dividends and common stock repurchases, sell assets, create liens that secure debt, enter into transactions with affiliates, merge or consolidate with other entities, and with respect to the Company’s restricted subsidiaries, permit the consensual restriction on the ability of such restricted subsidiaries to pay dividends or indebtedness owing to the Company or to any other restricted subsidiaries. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would resultwas in the Company settling the principal amount in cashcompliance with any excess value in shares of the Company’s common stock. The Senior Convertible Notes were not convertible at the option of holdersall financial and non-financial covenants as of September 30, 2017, or2022, and through the filing of this report. NotwithstandingPlease refer to Note 5 - Long-Term Debt in the inability to convert,2021 Form 10-K for additional detail on the if-converted value ofCompany’s covenants under the indentures governing the Senior Convertible Notes as of September 30, 2017, did not exceed the principal amount.Notes.

Capitalized Interest
Upon the issuance of the Senior Convertible Notes, the Company recorded $132.3 million as the initial carrying amount of the debt component, which approximated its fair value at issuance, and was estimated by using anCapitalized interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25%. The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.5 million and $7.4 million for the three months ended September 30, 2022, and 2021, totaled $5.1 million and $3.5 million, respectively, and totaled $12.3 million and $12.5 million for the nine months ended September 30, 2017,2022, and 2021, respectively.

The net carrying amount of interest the liability component of the Senior Convertible Notes, as reflectedCompany capitalizes generally fluctuates based on the accompanying balance sheets as of September 30, 2017,amount borrowed, the Company’s capital program, and December 31, 2016, consisted of the following:
 As of September 30, 2017 As of December 31, 2016
 (in thousands)
Principal amount of Senior Convertible Notes$172,500
 $172,500
Unamortized debt discount(32,048) (37,513)
Unamortized deferred financing costs(3,440) (4,131)
Net carrying amount$137,012
 $130,856

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notestiming and was in compliance with all such covenants as of September 30, 2017, and through the filing of this report.


Capped Call Transactions

In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The capped call transactions are generally expected to reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior Convertible Notescosts associated with capital projects that are considered in the event that the market price per share of the Company’s common stock is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call transactions, there could be dilution or there would not be an offset of such potential cash payments.progress. Capitalized interest costs are included in total costs incurred.

15

Note 6 - Commitments and Contingencies

Commitments

Other than those items discussed below, there have been no changes in commitments through the filing of this report that differ materially from those disclosed in the 2021 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the 2021 Form 10-K for additional discussion of the Company’s commitments.
Drilling Rig Service Contracts. During the first quarter of 2017, the Company completed the divestiture of its outside-operated Eagle Ford shale assets. Upon closing of the sale, the Company is no longer subject to gathering, processing, and transportation throughput commitments totaling 514 Bcf of gas, 52 MMBbl of oil, and 13 MMBbl of NGLs, or $501.9 million of the potential undiscounted deficiency payments as of December 31, 2016. As ofnine months ended September 30, 2017, the Company had total gathering, processing, transportation throughput,2022, and purchase commitments with various third parties that require delivery of a minimum quantity of 850 Bcf of gas, 15 MMBbl of oil, and 25 MMBbl of water through 2028 and a minimum purchase quantity of 16 MMBbl of water by 2022. If the Company fails to deliver or purchase any product, as applicable, the aggregate undiscounted deficiency payments totaled approximately $445.0 million as of September 30, 2017. As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to these commitments.

Additionally, the Company entered into new and amended certain of its drilling rig contracts duringresulting in the first nine monthsincrease of 2017day rates and subsequent to September 30, 2017.potential early termination fees, and the extension of contract terms. As of the filing of this report, the Company’s drilling rig commitments totaled $30.4 million; however, if$32.8 million under contract terms extending through the third quarter of 2023. If all of these contracts were terminated as of the filing of this report, the Company terminated thesewould avoid a portion of the contractual service commitments; however, the Company would be required to pay $19.6 million in early termination fees. No early termination penalties or standby fees were incurred by the Company during the nine months ended September 30, 2022, and the Company does not expect to incur material penalties with regard to its drilling rig contracts immediately, it would incur penalties of $17.5 million.

There were no other material changes in commitments during the firstremainder of 2022.
Drilling and Completion Commitments. During the nine months ended September 30, 2022, the Company entered into an agreement that includes minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2024, the Company will be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of 2017. Please referSeptember 30, 2022, the liquidated damages could range from zero to Note 6 - Commitments and Contingencies a maximum of $74.5 million, with the maximum exposure assuming no additional development activity occurred prior to the Company’s consolidated financial statements in its 2016 Form 10-K for additional discussionMarch 31, 2024. As of the Company’s commitments.

filing of this report, the Company expects to meet its obligations under this agreement.
Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. On July 7, 2017, Michael Lirette filedIn the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a Collective Action Complaint againstmaterial effect on the Company in the Southern District of Texas, claiming damages related to unpaid overtime wages under the Federal Fair Labor Standards Act. This case involves complex legal issues and uncertainties, a potentially large class of plaintiffs, and an alleged class period commencing in 2014. Because the proceedings are in the early stages, with discovery yet to be completed, the Company is unable to estimate what impact, if any, the action will have on its financial condition, results of operations, the financial position, or the cash flows.flows of the Company.

Note 7 - Compensation Plans

As of September 30, 2022, 3.8 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”). The Company may also grant other types of long-term incentive-based awards, such as cash awards and performance-based cash awards, to eligible employees.
Performance Share Units Under the Equity Incentive Compensation Plan

The Company grantshas granted performance share units (“PSUs”PSU” or “PSUs”) to eligible employees as part of its long-term equity compensation program.Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0%zero to 200% oftwo times the number of PSUs awarded and is determined based on certain performance criteria over a three-year measurementthree-year performance period. The performancePSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Equity Plan.
For PSUs granted in 2019, which the Company determined to be equity awards, the settlement criteria for PSUs are based onincluded a combination of the Company’s annualized Total Shareholder Return (“TSR”) forrelative to the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance criteria, the award agreements for these grants also stipulated that if the Company’s absolute TSR was negative over the three-year performance period, the maximum number of shares of common stock that could be issued to settle outstanding PSUs was capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair value of the PSUs granted in 2019 was measured on the grant date using the GBM Model, with the assumption that the associated CRTCI performance condition would be met at the target amount at the end of the performance period. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. PSUs granted in 2019 vested during the nine months ended September 30, 2022, and earned a 2.0 times multiplier upon settlement. The Company and all eligible recipients mutually agreed to net share settle a portion of the vested awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and the award agreement. After withholding 349,487 shares to satisfy income and payroll tax withholding obligations, 654,923 shares of the Company’s common stock were issued in accordance with the terms of the award agreement.

For PSUs granted in 2022, which the Company determined to be equity awards, settlement will be determined based on a combination of the following criteria measured over the three-year performance period: the Company’s TSR relative to the TSR of certain peer companies, the Company’s absolute TSR, free cash flow (“FCF”) generation, and the achievement of certain ESG targets, in each case as defined by the award agreement. The absolute and relative TSR portions of the fair value of the PSUs granted in 2022

16

were measured on the grant date using the GBM Model. The portion of the awards associated with FCF generation and ESG performance conditions assumes that target amounts will be met at the end of the performance period. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. The Company initially records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected FCF generation and achievement of certain ESG targets. During the nine months ended September 30, 2022, the Company granted a total of 276,010 PSUs with a grant date fair value of $7.4 million.
Total compensation expense recorded for PSUs was $0.6 million and $0.8 million for the three months ended September 30, 2017,2022, and 2016, was $2.62021, respectively, and $2.0 million and $2.3 million, respectively, and $6.8 million and $8.2$5.3 million for the nine months ended September 30, 2017,2022, and 2016,2021, respectively. As of September 30, 2017,2022, there was $22.0$6.8 million of total unrecognized compensation expense related to non-vested PSU awards,PSUs, which is being amortized through 2020.

mid-2025.
A summary of the status and activity of non-vested PSUs forduring the nine months ended September 30, 2017,2022, is presented in the following table:
PSUs (1)
 Weighted-Average Grant-Date Fair Value
PSUs (1)
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year828,923 $43.25
Non-vested at beginning of year464,483$12.80 
Granted977,731 $15.86
Granted276,010$26.67 
Vested(94,338) $85.85
Vested(460,928)$12.80 
Forfeited(168,658) $46.30
Forfeited(3,555)$12.80 
Non-vested at end of quarter1,543,658 $22.97
Non-vested at end of quarter276,010$26.67 

(1)
The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero to two.

(1)    The number of shares of common stock assumes a multiplier of one. The actual number of shares of common stock to be issued will range from zero to two times the number of PSUs awarded depending on the three-year performance multiplier.
During the nine months ended September 30, 2017, theEmployee Restricted Stock Units
The Company has granted 977,731 PSUs with a fair value of $15.5 millionrestricted stock units (“RSU” or “RSUs”) to eligible employees as part of its regular annual long-term equity compensation program. These PSUs generally vest on the third anniversary of the date of the grant. Also, during this period, the Company settled PSUs that were granted in 2014 with no shares issued upon settlement as the grant settled at a zero multiplier.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants restricted stock units (“RSUs”) as part of its long-term equity compensation program.Plan. Each RSU granted represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest in one-third increments on each anniversary date of the grant over the applicable vesting period or upon other triggering events as set forth in the Equity Plan.
The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the date of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards.

Total compensation expense recorded for RSUs was $2.9 million and $2.8 million for the three months ended September 30, 2017, and 2016, respectively, and $7.5 million and $9.3 million for the nine months ended September 30, 2017, and 2016, respectively. As of September 30, 2017, there was $22.8 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2020.

A summary of the status and activity of non-vested RSUs for the nine months ended September 30, 2017, is presented in the following table:
 RSUs Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year604,116 $37.39
Granted1,020,780 $16.64
Vested(251,575) $44.00
Forfeited(102,183) $28.43
Non-vested at end of quarter1,271,138 $20.14

During the nine months ended September 30, 2017,2022, the Company granted 1,020,780to employees a total of 526,776 RSUs with a grant date fair value of $16.9 million. These RSUs generally vest one-third of the total grant on each of the next three anniversary dates of the grant. Also, during the nine months ended September 30, 2017,$18.0 million, and the Company settled 246,025 RSUs that related toupon the vesting of awards granted in previous years. The Company and the majority of grant participantsall eligible recipients mutually agreed to net share settle a portion of the vested awards to cover income and payroll tax withholdings, as provided for in the plan documentEquity Plan and applicable award agreements. As a result, the Company issued 171,278 netAfter withholding 284,423 shares of common stock upon settlement of the awards. The remaining 74,747 shares were withheld to satisfy income and payroll tax withholding obligations, that occurred upon delivery636,504 shares of the shares underlying those RSUs.Company’s common stock were issued in accordance with the terms of the applicable award agreements during the nine months ended September 30, 2022.

Total compensation expense recorded for RSUs was $3.5 million and $2.9 million for the three months ended September 30, 2022, and 2021, respectively, and $10.0 million and $7.2 million for the nine months ended September 30, 2022, and 2021, respectively. As of September 30, 2022, there was $27.8 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through mid-2025.

A summary of activity during the nine months ended September 30, 2022, is presented in the following table:
RSUsWeighted-Average Grant-Date Fair Value
Non-vested at beginning of year1,841,237$13.79 
Granted526,776$34.08 
Vested(920,927)$12.17 
Forfeited(49,704)$16.62 
Non-vested at end of quarter1,397,382$22.41 
17


Director Shares

During the second quarter of 2017,nine months ended September 30, 2022, and 2021, the Company issued 71,573a total of 29,471 and 57,795 shares, respectively, of restrictedits common stock as compensation to its non-employee directors under the Company’s Equity Incentive Compensation Plan, whichPlan. Shares issued during 2022 will fully vest on December 31, 2017. Also2022, and shares issued during the second quarter of 2017, the Company issued 8,794 RSUs to a non-employee director, which2021 fully vestvested on December 31, 2017, and settle upon the earlier to occur of May 25, 2027, or the director resigning from the board of directors. The Company did not issue any director shares during the third quarter of 2017.

2021.
Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excesssubject to a maximum of 2,500 shares per offering period and a maximum of $25,000 in value fromrelated to purchases for each calendar year. The purchase price of the common stock is 85 percent of the lower of the fair market valuetrading price of the common stock on either the first or last day of the purchasesix-month offering period. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the Internal Revenue Code of 1986, as amended (“IRC”).Code. There were 123,678a total of 65,634 and 140,853252,665 shares issued under the ESPP during the nine months ended September 30, 2017,2022, and 2016,2021, respectively. Total proceeds to the Company for the issuance of these shares was $1.6 million and $1.3 million for the nine months ended September 30, 2022, and 2021, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Please refer to Note 87 - Pension Benefits

PensionCompensation Plans

The Company has a non-contributory defined benefit pension plan covering substantially all of its employees who joined the Company prior to January 1, 2015, and who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of December 31, 2015. Employees participating in the Pension Plans as of December 31, 2015, continue to earn benefits.2021 Form 10-K for additional detail on the Company’s Equity Plan.

Components of Net Periodic Benefit Cost for the Pension Plans

The following table presents the components of the net periodic benefit cost for the Pension Plans:
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in thousands)
Service cost$1,660
 $2,050
 $4,979
 $6,150
Interest cost673
 727
 2,017
 2,181
Expected return on plan assets that reduces periodic pension benefit cost(561) (559) (1,683) (1,677)
Amortization of prior service cost4
 4
 13
 13
Amortization of net actuarial loss324
 396
 973
 1,187
Net periodic benefit cost$2,100
 $2,618
 $6,299
 $7,854

Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.

Contributions

The Company contributed $7.0 million to the Qualified Pension Plan during the nine months ended September 30, 2017.

Note 8 - Fair Value Measurements
The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
•Level 1 – quoted prices in active markets for identical assets or liabilities
•Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
•Level 3 – significant inputs to the valuation model are unobservable
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of September 30, 2022:
Level 1Level 2Level 3
(in thousands)
Assets:
Derivatives (1)
$— $78,255 $— 
Liabilities:
Derivatives (1)
$— $189,223 $— 

(1)    This represents a financial asset or liability that is measured at fair value on a recurring basis.
18

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2021:
Level 1Level 2Level 3
(in thousands)
Assets:
Derivatives (1)
$— $24,334 $— 
Liabilities:
Derivatives (1)
$— $345,202 $— 

(1)    This represents a financial asset or liability that is measured at fair value on a recurring basis.
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Please refer to Note 10 - Derivative Financial Instruments in this report, and to Note 8 - Fair Value Measurements and Note 10 - Derivative Financial Instruments in the 2021 Form 10-K for more information regarding the Company’s derivative instruments.
Long-Term Debt
The following table reflects the fair value of the Company’s Senior Notes obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of September 30, 2022, or December 31, 2021, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt above for additional information.
As of September 30, 2022As of December 31, 2021
Principal AmountFair ValuePrincipal AmountFair Value
(in thousands)
10.0% Senior Secured Notes due 2025$— $— $446,675 $491,628 
5.0% Senior Notes due 2024$— $— $104,769 $104,583 
5.625% Senior Notes due 2025$349,118 $337,073 $349,118 $353,091 
6.75% Senior Notes due 2026$419,235 $401,627 $419,235 $431,787 
6.625% Senior Notes due 2027$416,791 $403,154 $416,791 $432,783 
6.5% Senior Notes due 2028$400,000 $381,456 $400,000 $417,284 
Note 9 - Earnings Per Share

Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing adjusted net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-

vestednon-vested RSUs, contingent PSUs, and shares intoWarrants, all of which the Senior Convertible Notes are convertible, which arewere measured using the treasury stock method.

PSUs represent The Warrants became exercisable at the right to receive, upon settlementelection of the PSUs after the completion of the three-year performance period,holders on January 15, 2021, and as a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number ofresult, they were included as potentially dilutive shares related to PSUs is basedsecurities on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs.

On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount of the Senior Convertible Notes in cash and the excess conversion value in shares. However, the Company has not made this an irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business circumstances warrant. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion priceadjusted weighted-average basis for the three andportion of the nine months ended September 30, 2017, and therefore, the Senior Convertible Notes had no dilutive impact. In connection with the offering2021, for which they were outstanding. A majority of the Senior Convertible Notes,Warrants were exercised during the Company entered into capped call transactions with affiliatessecond quarter of 2021, and the underwriters that would effectively prevent dilution upon settlement up toremaining outstanding Warrants were dilutive during the $60.00 cap price. The capped call transactions are not reflected in diluted net income (loss) per share, nor will they ever be,three months ended September 30, 2022, and 2021, and the nine months ended September 30, 2022, as they are anti-dilutive.presented below. Please refer to Note 53 - Long-Term DebtEquity and Note 7 - Compensation Plans in this report, and Note 9 - Earnings Per Share in the 2021 Form 10-K for additional discussion.detail on these potentially dilutive securities.

19

When the Company recognizes a net loss from continuing operations, as was the case for all periods presented, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share.

The following table details the weighted-average number of anti-dilutive securities for the periods presented:
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in thousands)
Anti-dilutive—
 506
 78
 193

For the Three Months Ended
September 30,		For the Nine Months Ended
September 30,
2022202120222021
(in thousands)
Anti-dilutive———5,200
The following table sets forth the calculations of basic and diluted net lossincome (loss) per common share:
For the Three Months Ended
September 30,		For the Nine Months Ended
September 30,
2022202120222021
(in thousands, except per share data)
Net income (loss)$481,240 $85,593 $853,489 $(388,671)
Basic weighted-average common shares outstanding123,195121,457122,318118,224
Dilutive effect of non-vested RSUs and contingent PSUs1,0652,3751,896—
Dilutive effect of Warrants191919—
Diluted weighted-average common shares outstanding124,279123,851124,233118,224
Basic net income (loss) per common share$3.91 $0.70 $6.98 $(3.29)
Diluted net income (loss) per common share$3.87 $0.69 $6.87 $(3.29)
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in thousands, except per share amounts)
Net loss$(89,112) $(40,907) $(134,585) $(556,798)
Basic weighted-average common shares outstanding111,575
 78,468
 111,366
 71,574
Add: dilutive effect of non-vested RSUs and contingent PSUs—
 —
 —
 —
Add: dilutive effect of Senior Convertible Notes—
 —
 —
 —
Diluted weighted-average common shares outstanding111,575
 78,468
 111,366
 71,574
Basic net loss per common share$(0.80) $(0.52) $(1.21) $(7.78)
Diluted net loss per common share$(0.80) $(0.52) $(1.21) $(7.78)

Note 10 - Derivative Financial Instruments

Summary of Oil, Gas, and NGL Derivative Contracts in Place
The Company has enteredregularly enters into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity pricesoil, gas, and NGL price volatility and location differentials, and the associated impact on cash flows. As of September 30, 2017, all derivative counterparties were members of the Company’s credit facility lender group and2022, all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of price swap and collar arrangements.arrangements for oil, gas, and NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed

price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.
The Company has entered into fixed price oil and gas basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production is sold. As of September 30, 2022, the Company has basis swap contracts with fixed price differentials between:
•NYMEX WTI and WTI Midland for a portion of its Midland Basin oil production with sales contracts that settle at WTI Midland prices;
•NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices;
•NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“MEH”) for a portion of its South Texas oil production with sales contracts that settle at Argus WTI Houston MEH (“WTI Houston MEH”) prices;
•NYMEX HH and Inside FERC West Texas (“IF Waha”) for a portion of its Midland Basin gas production with sales contracts that settle at IF Waha prices; and
•NYMEX HH and Inside FERC Houston Ship Channel (“IF HSC”) for a portion of its South Texas gas production with sales contracts that settle at IF HSC prices.
20

The Company has also entered into oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.
As of September 30, 2017,2022, the Company had commodity derivative contracts outstanding through the fourth quarter of 2025 as summarized in the tablestable below:

Oil Swaps
Contract Period
Fourth Quarter 2022202320242025
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes1,923 1,190 — — 
Weighted-Average Contract Price$44.58 $45.20 $— $— 
ICE Brent Volumes— 3,650 910 — 
Weighted-Average Contract Price$— $86.50 $85.50 $— 
Collars
NYMEX WTI Volumes1,128 1,331 919 — 
Weighted-Average Floor Price$63.74 $66.01 $75.00 $— 
Weighted-Average Ceiling Price$75.48 $80.79 $81.47 $— 
Basis Swaps
WTI Midland-NYMEX WTI Volumes2,462 3,613 — — 
Weighted-Average Contract Price$1.15 $0.73 $— $— 
ICE Brent-NYMEX WTI Volumes920 — — — 
Weighted-Average Contract Price$(7.78)$— $— $— 
WTI Houston MEH-NYMEX WTI Volumes374 1,234 — — 
Weighted-Average Contract Price$1.25 $1.52 $— $— 
Roll Differential Swaps
NYMEX WTI Volumes3,248 4,968 — — 
Weighted-Average Contract Price$0.21 $0.62 $— $— 
Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes2,806 — — — 
Weighted-Average Contract Price$5.50 $— $— $— 
IF HSC Volumes6,982 — — — 
Weighted-Average Contract Price$2.47 $— $— $— 
IF Waha Volumes3,067 900 — — 
Weighted-Average Contract Price$2.22 $3.98 $— $— 
Collars
NYMEX HH Volumes1,908 24,170 — — 
Weighted-Average Floor Price$3.50 $3.74 $— $— 
Weighted-Average Ceiling Price$4.44 $6.32 $— $— 
IF HSC Volumes— 5,085 — — 
Weighted-Average Floor Price$— $4.10 $— $— 
Weighted-Average Ceiling Price$— $5.63 $— $— 
21



Contract Period
 NYMEX WTI Volumes 
Weighted-Average
 Contract Price
  (MBbls) (per Bbl)
Fourth quarter 2017 1,510
 $47.11
2018 6,272
 $49.82
2019 1,940
 $50.70
Total 9,722
  
Contract Period (continued)
Fourth Quarter 2022202320242025
Basis Swaps
IF Waha-NYMEX HH Volumes— 7,247 20,958 20,501 
Weighted-Average Contract Price$— $(1.02)$(0.86)$(0.66)
IF HSC-NYMEX HH Volumes— 9,582 — — 
Weighted-Average Contract Price$— $0.07 $— $— 
NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
OPIS Propane Mont Belvieu Non-TET Volumes113 — — — 
Weighted-Average Contract Price$35.91 $— $— $— 
Collars
OPIS Propane Mont Belvieu Non-TET Volumes173 — — — 
Weighted-Average Floor Price$24.11 $— $— $— 
Weighted-Average Ceiling Price$28.13 $— $— $— 

Oil Collars
Contract Period 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
  (MBbls) (per Bbl) (per Bbl)
Fourth quarter 2017 1,086
 $47.51
 $56.05
2018 5,030
 $50.00
 $58.07
2019 3,128
 $50.00
 $58.84
Total 9,244
    

Oil Basis Swaps


Contract Period
 Midland-Cushing Volumes 
Weighted-Average
 Contract Price (1)
  (MBbls) (per Bbl)
Fourth quarter 2017 1,856
 $(1.50)
2018 8,734
 $(1.27)
2019 3,963
 $(1.45)
Total 14,553
  

(1)
Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma.

Commodity Derivative Contracts Entered Into Subsequent to September 30, 2022
Subsequent to September 30, 2017,2022, the Company entered into Midland-Cushingthe following commodity derivative contracts:
•WTI Midland-NYMEX WTI basis swap contracts for 20182023 for a total of 1.4 million Bbls1.7 MMBbl of oil production at a weighted-average contract price of $1.36 per Bbl;
•WTI Houston MEH-NYMEX WTI basis swap contracts for the first and second quarters of 2023 for a total of 0.2 MMBbl of oil production at a weighted-average contract price of $2.11 per Bbl;
•NYMEX HH swap contracts for the second and third quarters of 2023 for a total of 2,890 BBtu of gas production at a weighted-average contract price of $5.08 per MMBtu;
•NYMEX HH collar contracts for the fourth quarter of 2023 and the first quarter of 2024 for a total of 3,423 BBtu of gas production at a weighted-average floor price of $4.27 per MMBtu and a weighted-average ceiling price of $8.52 per MMBtu; and
•IF HSC-NYMEX HH basis swap contract for the second through fourth quarters of 2023 for a total of 2,750 BBtu of gas production at a contract price of ($0.33)$(0.30) per Bbl.

Natural Gas Swaps
Contract Period 
Sold
Volumes
 
Weighted-Average
 Contract Price
 
Purchased Volumes (1)
 Weighted- Average Contract Price 
Net
Volumes
  (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu)
Fourth quarter 2017 22,001
 $3.98
 —
 $—
 22,001
2018 102,900
 $3.37
 (30,606) $4.27
 72,294
2019 41,394
 $3.76
 (24,415) $4.34
 16,979
Total (2)
 166,295
   (55,021)   111,274

(1)
During 2016, the Company restructured certain of its natural gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No other cash or other consideration was included as part of the restructuring.
(2)
Total net volumes of natural gas swaps are comprised of IF El Paso Permian (1%), IF HSC (98%), and IF NNG Ventura (1%).

NGL Swaps
  OPIS Purity Ethane Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET OPIS Natural Gasoline Mont Belvieu Non-TET
Contract Period Volumes
Weighted-Average
 Contract Price
 VolumesWeighted-Average
Contract Price		 VolumesWeighted-Average
Contract Price		 VolumesWeighted-Average
Contract Price		 VolumesWeighted-Average
Contract Price
  (MBbls)(per Bbl) (MBbls)(per Bbl) (MBbls)(per Bbl) (MBbls)(per Bbl) (MBbls)(per Bbl)
Fourth quarter 2017 966
$9.65
 653
$24.24
 214
$35.29
 174
$35.60
 203
$48.41
2018 4,017
$11.00
 2,464
$24.74
 391
$35.14
 308
$34.72
 427
$48.44
2019 3,112
$12.27
 1,036
$26.49
 —
$—
 —
$—
 —
$—
2020 539
$11.13
 —
$—
 —
$—
 —
$—
 —
$—
Total 8,634
  4,153
  605
  482
  630
 


MMBtu.
Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities.liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. The fair value of the commodity derivative contracts was a net liability of $31.7$111.0 million and $320.9 million as of September 30, 2017,2022, and a net liability of $91.7 million as of December 31, 2016.2021, respectively.

22

The following tables detailtable details the fair value of derivativescommodity derivative contracts recorded in the accompanying balance sheets, by category:
 As of September 30, 2017
 Derivative Assets Derivative Liabilities
 
Balance Sheet
 Classification
 Fair Value 
Balance Sheet
 Classification
 Fair Value
 (in thousands)
Commodity contractsCurrent assets $63,685
 Current liabilities $87,791
Commodity contractsNoncurrent assets 60,035
 Noncurrent liabilities 67,676
Derivatives not designated as hedging instruments  $123,720
   $155,467

 As of December 31, 2016
 Derivative Assets Derivative Liabilities
 
Balance Sheet
 Classification
 Fair Value 
Balance Sheet
 Classification
 Fair Value
 (in thousands)
Commodity contractsCurrent assets $54,521
 Current liabilities $115,464
Commodity contractsNoncurrent assets 67,575
 Noncurrent liabilities 98,340
Derivatives not designated as hedging instruments  $122,096
   $213,804

As of September 30, 2022As of December 31, 2021
(in thousands)
Derivative assets:
Current assets$42,207 $24,095 
Noncurrent assets36,048 239 
Total derivative assets$78,255 $24,334 
Derivative liabilities:
Current liabilities$174,717 $319,506 
Noncurrent liabilities14,506 25,696 
Total derivative liabilities$189,223 $345,202 
Offsetting of Derivative Assets and Liabilities

As of September 30, 2017,2022, and December 31, 2016,2021, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:
Derivative Assets as ofDerivative Liabilities as of
September 30,
2022		December 31, 2021September 30,
2022		December 31, 2021
(in thousands)
Gross amounts presented in the accompanying balance sheets$78,255 $24,334 $(189,223)$(345,202)
Amounts not offset in the accompanying balance sheets(56,524)(22,862)56,524 22,862 
Net amounts$21,731 $1,472 $(132,699)$(322,340)
23
  Derivative Assets Derivative Liabilities
  As of As of
Offsetting of Derivative Assets and Liabilities September 30, 
 2017		 December 31, 2016 September 30, 
 2017		 December 31, 2016
  (in thousands)
Gross amounts presented in the accompanying balance sheets $123,720
 $122,096
 $(155,467) $(213,804)
Amounts not offset in the accompanying balance sheets (85,195) (118,080) 85,195
 118,080
Net amounts $38,525
 $4,016
 $(70,272) $(95,724)


The following table summarizes the commodity components of the derivative settlement loss, and the net derivative (gain) loss line items presented inwithin the accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) and the accompanying statements of operations:operations, respectively:
For the Three Months Ended September 30,For the Nine Months Ended September 30,
For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,		2022202120222021
2017 2016 2017 2016
(in thousands)(in thousands)
Derivative settlement (gain) loss:       
Derivative settlement loss:Derivative settlement loss:
Oil contracts$2,472
 $(49,241) $14,310
 $(221,397)Oil contracts$120,430 $154,113 $428,811 $344,740 
Gas contracts(24,088) (10,096) (63,345) (82,588)Gas contracts61,981 35,757 142,369 88,437 
NGL contracts8,524
 1,841
 19,633
 (2,249)NGL contracts3,888 23,685 23,900 47,085 
Total derivative settlement gain$(13,092) $(57,496) $(29,402) $(306,234)
Total derivative settlement lossTotal derivative settlement loss$186,299 $213,555 $595,080 $480,262 
       
Total net derivative (gain) loss:       
Net derivative (gain) loss:Net derivative (gain) loss:
Oil contracts$45,874
 $(733) $(41,910) $49,608
Oil contracts$(180,300)$68,194 $235,023 $611,224 
Gas contracts(6,068) (14,006) (56,574) 24,460
Gas contracts47,973 109,802 142,695 220,088 
NGL contracts40,793
 (13,298) 9,120
 47,018
NGL contracts(5,250)31,150 7,462 92,871 
Total net derivative (gain) loss$80,599
 $(28,037) $(89,364) $121,086
Total net derivative (gain) loss$(137,577)$209,146 $385,180 $924,183 
Credit Related Contingent Features

As of September 30, 2017, and through the filing of this report,2022, all of the Company’s derivative counterparties were members of the Company’sCredit Agreement lender group, with the exception of one counterparty with whom the Company has derivative contracts outstanding through December 31, 2022, that was a part of the lender group under the prior credit facilityagreement. The contracts with this counterparty were entered into while the counterparty was a member of the prior credit agreement lender group. The Company does not enter into derivative contracts with counterparties that are not part of the lender group. Under the Credit Agreement, and derivative contracts, the Company is required to secure mortgagesprovide mortgage liens on assets having a value equal to at least 9085 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

24

Note 11 - Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
Level 1 – quoted prices in active markets for identical assets or liabilities
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3 – significant inputs to the valuation model are unobservable
The following table summarizes the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of September 30, 2017:

Level 1
Level 2
Level 3

(in thousands)
Assets:     
Derivatives (1)
$—
 $123,720
 $—
Liabilities:     
Derivatives (1)
$—
 $155,467
 $—

(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.


The following table summarizes the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2016:
 Level 1 Level 2 Level 3
 (in thousands)
Assets:     
Derivatives (1)
$—
 $122,096
 $—
Total property and equipment, net (2)
$—
 $—
 $88,205
Liabilities:     
Derivatives (1)
$—
 $213,804
 $—

(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2)
This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Additionally, all of the Company’s derivative counterparties are members of the Company’s credit facility lender group.

Please refer to Note 10 - Derivative Financial Instrumentsabove and to Note 11 - Fair Value Measurements in the Company’s 2016 Form 10-K for more information regarding the Company’s derivative instruments.

Proved and Unproved Oil and Gas Properties and Other Property and Equipment

The Company did not have property and equipment measured at fair value within the accompanying balance sheets as of September 30, 2017. Property and equipment, net measured at fair value totaled $88.2 million as of December 31, 2016, and primarily consisted of the Company’s Powder River Basin assets, which were impaired at year-end as a result of downward performance reserve revisions.
Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. The calculation of the discount rates are based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of September 30, 2017, and December 31, 2016. The Company believes the discount rates are representative of current market conditions and consider estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates.

The Company did not recognize any material impairment of proved properties expenses for the three or nine months ended September 30, 2017, or for the three months ended September 30, 2016. The Company recorded impairment of proved properties expense of $277.8 million for the nine months ended September 30, 2016, primarily related to the decline in proved and risk-adjusted probable and possible reserve expected cash flows from the Company’s outside-operated Eagle Ford shale assets, driven by commodity price declines during the first quarter of 2016. These properties were sold during the first quarter of 2017. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions for more information regarding divestiture activity.

Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable.  To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.

There were no material abandonments or impairments of unproved properties expenses for the three or nine months ended September 30, 2017 or 2016.

Oil and gas properties held for sale. Proved and unproved properties and other property and equipment classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available, or by recent, comparable market transactions. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. When assets no longer meet the criteria of assets held for sale, they are measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense that would have been recognized, or the fair value at the date they are reclassified to assets held for use.

There were no material assets held for sale that were recorded at fair value as of September 30, 2017. However, for the nine months ended September 30, 2017, the Company recorded a $526.5 million write-down on its Divide County, North Dakota, assets previously held for sale, of which $359.6 million was recorded in the first quarter of 2017 based on an estimated fair value less selling costs and $166.9 million was recorded in the second quarter of 2017 based on market conditions that existed on the date the Company decided to retain the assets. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitionsfor additional discussion.

Long-Term Debt

The following table reflects the fair value of the Senior Notes and Senior Convertible Notes measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of September 30, 2017, or December 31, 2016, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion.
 As of September 30, 2017 As of December 31, 2016
 Principal Amount Fair Value Principal Amount Fair Value
 (in thousands)
6.50% Senior Notes due 2021$344,611
 $349,780
 $346,955
 $354,546
6.125% Senior Notes due 2022$561,796
 $565,830
 $561,796
 $570,925
6.50% Senior Notes due 2023$394,985
 $397,947
 $394,985
 $403,134
5.0% Senior Notes due 2024$500,000
 $471,660
 $500,000
 $475,975
5.625% Senior Notes due 2025$500,000
 $477,350
 $500,000
 $485,000
6.75% Senior Notes due 2026$500,000
 $502,500
 $500,000
 $516,565
1.50% Senior Convertible Notes due 2021$172,500
 $163,240
 $172,500
 $202,189

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ThisThe following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statementsat the endsection of this itemreport for important information about these types of statements.

Additionally, the following discussion includes sequential quarterly comparison to the financial information presented in our Quarterly Report onForm 10-Q for the quarter ended June 30, 2022, filed with the SEC on August 4, 2022. Throughout the following discussion, we explain changes between the three months ended September 30, 2022, and the three months ended June 30, 2022 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the nine months ended September 30, 2022, and the nine months ended September 30, 2021 (“YTD 2022-over-YTD 2021”).
Overview of the Company Highlights, and Outlook

General Overview

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our strategic objective is to be a premier operator of top tiertop-tier oil and gas assets. Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision is to sustainably grow value for all of our stakeholders. Our strategy for achieving our goals is to focus on high-quality economic drilling, completion, and production opportunities. Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas. With our continued success in generating cash flows and reducing our outstanding principal debt balance, our short-term goals include returning value to stockholders in a sustainable and repeatable way through our Stock Repurchase Program and recently increased fixed dividend payments.
We seekare committed to maximizeexceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive impact in the communities where we live and work; and transparency in reporting on our progress in these areas. We have prioritized ESG initiatives by, among other things, integrating enhanced environmental and social programs throughout the organization and setting near-term and medium-term goals that include reducing flaring and greenhouse gas emissions intensity and maintaining low methane emissions intensity. Additionally, we are implementing systems to track additional ESG metrics, to improve future reporting, and to increase employee awareness. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s ESG policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide performance-based metrics that include key financial, operational, environmental, health, and safety measures.
Global commodity and financial markets remain subject to heightened levels of uncertainty and volatility as a result of inflation, macroeconomic uncertainty, the ongoing conflict between Russia and Ukraine and associated economic and trade sanctions on Russia, and the Pandemic. These issues have contributed to increased service provider costs, supply chain disruptions, a rise in interest rates, and could have further industry-specific impacts, which may require us to adjust our business plan. For additional detail, please refer to the Risk Factors section in Part I, Item 1A of our 2021 Form 10-K. Despite continuing impacts of geopolitical issues and future macroeconomic uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and maximizing the value of our top-tier Midland Basin and South Texas assets.
Areas of Operations
Our Midland Basin assets by applying industry leading technology and outstanding operational execution. Our portfolio isare comprised of unconventional resource prospects with prospective drilling opportunities, which we believe provide for long-term production and reserves growth. We focus on achieving high full-cycle economic returns on our investments and maintaining a simple, strong balance sheet.

We currently have material core producing assets and acreage positionsapproximately 80,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the third quarter of 2022, drilling and completion activities within our RockStar and Sweetie Peck positions continued to focus primarily on development optimization and further delineating our Midland Basin position. Our Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
Our South Texas assets are comprised of approximately 155,000 net acres located in the Maverick Basin in Dimmit and Webb Counties, Texas (“South Texas”). In the third quarter of 2022, our operations in South Texas were focused on production from both the Austin Chalk formation and Eagle Ford shale in Texas, as well as producing assetsformation, and materialfurther development of the Austin Chalk formation. Our overlapping acreage positionsposition in the Powder RiverMaverick Basin covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.
Our 2022 capital program is expected to be between $870.0 million and $900.0 million. Our financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our 2022 capital program remains focused on highly economic oil development projects in Wyoming,both our Midland Basin and the Bakken/Three Forks play in North Dakota. During 2016, and continuing into 2017, we made several proved and unproved property acquisitions and tradesSouth Texas assets. We believe that our high-quality asset portfolio is capable of generating strong returns in the Midland Basin, while divesting non-core assets in other areas. By actively managingcurrent macroeconomic environment, which we expect will
25

enable us to grow cash flows, improve leverage metrics, and maintain strong financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our asset portfolio in this way, we are seeking to concentrate our investments in areas with the highest economic returns and provide value through accelerated development activity.2022 capital program.

Third Quarter 2017 Highlights2022 Overview and Outlook for the Remainder of 20172022

Our priorities for 2017, as set atDuring the beginning of the year, were to:

demonstrate the value of our 2016 and 2017 acquisitions in the Midland Basin;
generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;
successfully execute the sale of our outside-operated Eagle Ford shale and Divide County, North Dakota, assets; and
reduce our outstanding debt.

With respect to our 2017 priorities, we have focused on demonstrating the significant value potential of our Midland Basin position and coring up this position in order to maximize long-term growth. We successfully closed the sale of our outside-operated Eagle Ford shale assets in the firstthird quarter of 2017 for net divestiture proceeds2022, our Board of $747.4 million. Proceeds from this divestiture continueDirectors authorized the Stock Repurchase Program and increased our fixed dividend to provide us with significant liquidity and will support funding our capital program for the remainder of the year. During the second quarter of 2017, we made the decision to retain our Divide County, North Dakota, assets as valuations in the sales process did not reach our expectations.  We will continue to use cash flows from our Divide County, North Dakota, assets to fund higher margin production growth projects within our portfolio.
We expect our capital program for 2017, excluding acquisitions,$0.60 per share annually, to be approximately $875 million. We have been concentratingpaid in quarterly increments of $0.15 per share, both of which align with our goal to implement a sustainable and repeatable capital on our highest return programs and have been operating at strong performance levels to generate higher company-wide margins and cash flow growth while creatingprogram that creates long-term value for our stockholders. During the three months ended September 30, 2022, we repurchased and subsequently retired 452,734 shares of our outstanding common stock at a cost of $20.2 million. Please refer to OverviewNote 3 - Equity in Part I, Item 1 of Liquiditythis report for additional discussion.
Financial and Capital ResourcesOperational Results. Average net daily equivalent production for the three months ended September 30, 2022, decreased six percent sequentially to 137.8 MBOE, consisting of decreases in oil volumes of nine percent, or 5.8 MBbl per day, gas volumes of three percent, or 9.9 MMcf per day, and NGL volumes of six percent, or 1.4 MBbl per day.
Oil and NGL realized prices, before the effect of derivative settlements (“realized price” or “realized prices”), decreased sequentially by 15 percent and 14 percent, respectively, as a result of decreases in benchmark commodity prices during the third quarter of 2022. Realized prices for gas remained flat sequentially. Total realized price per BOE decreased 12 percent sequentially. The decrease in total realized price per BOE and the decrease in total net equivalent production volumes resulted in a 16 percent sequential decrease in oil, gas, and NGL production revenue, which was $827.6 million for the three months ended September 30, 2022, compared with $990.4 million for the three months ended June 30, 2022. Oil, gas, and NGL production expense per BOE of $12.62 for the three months ended September 30, 2022, increased two percent sequentially, primarily as a result of increases in lease operating expense (“LOE”) per BOE and ad valorem tax expense per BOE, mostly offset by a decrease in production tax expense per BOE.
We recorded a net derivative gain of $137.6 million for the three months ended September 30, 2022, compared with a net derivative loss of $104.2 million for the three months ended June 30, 2022. Included within these amounts are derivative settlement losses of $186.3 million and $240.6 million for the three months ended September 30, 2022, and June 30, 2022, respectively.
Operational and financial activities during the three months ended September 30, 2022, resulted in the following:
•Net cash provided by operating activities of $513.4 million for the three months ended September 30, 2022, compared with $542.6 million for the three months ended June 30, 2022.
•Net income of $481.2 million, or $3.87 per diluted share, for the three months ended September 30, 2022, compared with net income of $323.5 million, or $2.60 per diluted share, for the three months ended June 30, 2022.
•Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2022, of $460.2 million, compared with $559.7 million for the three months ended June 30, 2022. Please refer to the caption Non-GAAP Financial Measuresbelow for additional discussion on how we expectand our definition of adjusted EBITDAX and reconciliations to fund our 2017 capital program.net income (loss) and net cash provided by operating activities.
Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2022, and June 30, 2022, and Between the Nine Months Ended September 30, 2022, and 2021 below for additional discussion.
Operational Activities. In our Midland Basin program, we operated seventhree drilling rigs and threetwo completion crews, drilled 12 gross (10 net) wells and completed 15 gross (14 net) wells during the third quarter of 2017. Of these seven drilling rigs,2022. Net equivalent production volumes decreased sequentially by five were focused on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals on our acreage positionpercent to 7.2 MMBOE. Costs incurred in Howard and Martin Counties, Texas, and the other two drilling rigs focused on developing the Wolfcamp A and B and Lower Spraberry shale intervals on our Sweetie Peck property in Upton and Midland Counties, Texas. Subsequent to September 30, 2017, we added a fourth completion crew and entered into an agreement to add an eighth drilling rig, which we expect to begin operating during the fourth quarter of 2017. We expect approximately 80 percent of our 2017 capital program to be dedicated to our Midland Basin program.

During the first nine months of 2017, we acquired approximately 3,400 net acres of primarily unproved properties in the Midland Basin in multiple transactions totaling $72.2 million of cash consideration. Additionally, we completed several non-monetary acreage trades consisting primarily of unproved acreage of approximately 7,425 net acres in exchange for approximately 6,725 net acres in Howard and Martin Counties, Texas with $283.7 million of value attributed to the properties that we assigned in such trades. These trades, which we recorded at carryover basis with no gain or loss recognized, increased our working interest in existing drilling units and also provide us the opportunity to drill longer lateral wells.
In our Eagle Ford shale program we began the third quarter of 2017 running one drilling rig and added one drilling rig during the quarter. We remain focused on drilling and completion optimization and meeting lease obligations. We expect approximately 20 percent of our 2017 capital program to be dedicated to our Eagle Ford shale program.
In September 2017, we entered into a joint venture agreement with a third party to drill 16 wells and complete 23 wells in a focused portion of our Eagle Ford North area.  This partnership allows us to use third party resources to test cutting edge technology, accelerate the capture of technical data, and hold acreage in this area, potentially expanding economic drilling inventory and acreage value. Moreover, we expect this partnership will result in further optimizations outside of the joint venture area, enhancing the overall value of our Eagle Ford asset. The objectives of this agreement are similar to our highly successful, ongoing joint venture arrangement in the Powder River Basin discussed below.  Per the terms of the agreement, our working interest was reduced in seven wells completed during the third quarter of 2017. The joint venture is expected to result in drilling six carried wells in the joint venture area in the fourth quarter of 2017.
In our Powder River Basin program, we continued running one drilling rig during the third quarter of 2017 under an acquisition and development funding agreement with a third party, pursuant to which the third party is carrying our drilling and completion costs.
Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $226.6 million and $741.6 million for the three and nine months ended September 30, 2017, respectively. Costs incurred in 2017 were primarily in our Midland Basin and operated Eagle Ford shale program. Of2022, totaled $129.0 million, or 51 percent of our total costs incurred for the nineperiod. During the remainder of 2022, we anticipate operating three drilling rigs and one completion crew. Activity is expected to focus primarily on developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions.
In our South Texas program, we operated two drilling rigs and averaged one completion crew, drilled eight gross (eight net) wells and completed 17 gross (17 net) wells during the third quarter of 2022. Net equivalent production volumes decreased sequentially by five percent to 5.5 MMBOE. Costs incurred in our South Texas program during the three months ended September 30, 2017, $76.62022, totaled $110.7 million, related to property acquisitions, primarily unproved, in Howard and Martin Counties, Texas, which were incurred in the first halfor 44 percent of 2017. Additionally, we completed several non-monetary acreage trades in the Midland Basin during the first nine months of 2017 totaling $283.7 million of value attributed to the properties surrendered. This non-monetary consideration is not reflected in theour total costs incurred amounts presented above.for the period. During the remainder of 2022, we anticipate operating two drilling rigs and one completion crew, focused primarily on developing the Austin Chalk formation.

26

Drilling and Completion Activity. The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs during the nine months ended September 30, 2017:
 Midland Basin Eagle Ford Shale Bakken/Three Forks Total
 Gross Net Gross Net Gross Net Gross Net
Wells drilled but not completed at December 31, 201617
 17
 47
 47
 20
 17
 84
 81
Wells drilled19
 19
 5
 5
 —
 —
 24
 24
Wells completed(16) (16) (17) (17) —
 —
 (33) (33)
Wells drilled but not completed at March 31, 201720
 20
 35
 35
 20
 17
 75
 72
Wells drilled24
 23
 6
 6
 —
 —
 30
 29
Wells completed(9) (9) (14) (14) —
 —
 (23) (23)
Wells drilled but not completed at June 30, 201735
 34
 27
 27
 20
 17
 82
 78
Wells drilled29
 25
 6
 6
 —
 —
 35
 31
Wells completed(23) (23) (7) (4) —
 —
 (30) (27)
Other (1)
—
 —
 —
 (3) —
 —
 —
 (3)
Wells drilled but not completed at September 30, 201741
 36
 26
 26
 20
 17
 87
 79

(1)
Reflects net working interest changes resulting from the Eagle Ford North joint venture agreement discussed above.


Production Results. The table below provides a regional breakdown of our production for the three and nine months ended September 30, 2017:2022:
Midland Basin
South Texas (1)
Total
GrossNetGrossNetGrossNet
Wells drilled but not completed at December 31, 202130 27 32 32 62 59 
Wells drilled16 14 9 9 25 23 
Wells completed(6)(5)(13)(13)(19)(18)
Wells drilled but not completed at March 31, 202240 36 28 28 68 64 
Wells drilled (2)
16 13 11 10 27 23 
Wells completed (2)
(7)(7)(2)(2)(9)(9)
Wells drilled but not completed at June 30, 2022 (3)
49 41 37 36 86 78 
Wells drilled12 10 8 8 20 18 
Wells completed(15)(14)(17)(17)(32)(31)
Wells drilled but not completed at September 30, 2022 (3)
46 38 28 27 74 65 

(1)    The South Texas drilled but not completed well count includes 11 gross (11 net) wells that were not included in our five-year development plan at December 31, 2021.
(2)    Wells drilled and wells completed during the three months ended June 30, 2022, exclude one drilled and completed well that was subsequently abandoned, outside of our core areas of operations.
(3)    Amounts may not calculate due to rounding.
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $253.8 million and $677.4 million for the three and nine months ended September 30, 2022, respectively, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.
27

 Permian South Texas & Gulf Coast Rocky Mountain Total
 Three Months EndedNine Months Ended Three Months EndedNine Months Ended Three Months EndedNine Months Ended Three Months EndedNine Months Ended
Oil (MMBbl)2.3
5.6
 0.4
1.6
 0.7
2.6
 3.4
9.8
Gas (Bcf)3.9
10.1
 24.2
83.8
 1.0
3.1
 29.1
97.0
NGLs (MMBbl)—
—
 2.4
8.0
 —
0.1
 2.4
8.1
Equivalent (MMBOE)3.0
7.3
 6.7
23.5
 1.0
3.2
 10.7
34.1
Avg. daily equivalents (MBOE/d)32.3
26.9
 73.3
86.2
 10.4
11.8
 116.0
124.9
Relative percentage28%22% 63%69% 9%9% 100%100%
Production Results. The table below presents our production by product type for each of our assets for the sequential quarterly periods and the YTD 2022-over-YTD 2021 periods:
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
Midland Basin Production:
Oil (MMBbl)4.5 4.9 14.7 18.5 
Gas (Bcf)16.1 16.0 47.5 38.9 
NGLs (MMBbl)— — — — 
Equivalent (MMBOE)7.2 7.6 22.6 25.0 
Average net daily equivalent (MBOE per day)78.1 83.2 82.9 91.6 
Relative percentage57 %57 %57 %68 %
South Texas Production:
Oil (MMBbl)1.2 1.2 3.6 1.7 
Gas (Bcf)14.9 15.5 46.3 38.2 
NGLs (MMBbl)1.8 1.9 5.9 3.8 
Equivalent (MMBOE)5.5 5.8 17.2 11.8 
Average net daily equivalent (MBOE per day)59.7 63.4 63.0 43.2 
Relative percentage43 %43 %43 %32 %
Total Production:
Oil (MMBbl)5.7 6.1 18.3 20.2 
Gas (Bcf)31.0 31.5 93.8 77.1 
NGLs (MMBbl)1.8 1.9 5.9 3.8 
Equivalent (MMBOE)12.7 13.3 39.8 36.8 
Average net daily equivalent (MBOE per day)137.8 146.6 145.8 134.8 

Note: Amounts may not calculate due to rounding.

Production on an equivalent basis decreased 25 percent and 19 percent for the three and nine months ended September 30, 2017, compared with the same periods in 2016. Production declines were primarily a result of property divestitures, which occurred in the last half of 2016 and the first quarter of 2017, specifically our Raven/Bear Den and outside-operated Eagle Ford shale assets. These declines were partially offset by increased production in our Permian region. The production decline also includes the effects of Hurricane Harvey of approximately 0.2 MMBOE due to intermittent curtailments in certain production due to downstream, third-party facilities that were impacted by the storm. All of our production, drilling, and completion operations have since returned to normal. When excluding production from all assets sold in 2016 and 2017, production from retained assets increased approximately seven percent and 11 percent for the three and nine months ended September 30, 2017, compared with the same periods in 2016, respectively, which is being driven primarily by the ramp up in our Midland Basin development program. Please refer toA Three-Month and Nine-Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2022, and June 30, 2022, and Between the Nine Months Ended September 30, 2017,2022, and 2016 2021 below for additional discussion on production.

Financial Results. In the third quarter of 2017, we had the following financial results:

We recorded a net loss of $89.1 million, or $0.80 per diluted share, for the three months ended September 30, 2017, compared with a net loss of $40.9 million, or $0.52 per diluted share, for the same period in 2016. Please refer to Comparison of Financial Results and Trends Between the Three Months and Nine Months Ended September 30, 2017, and 2016 below for additional discussion regarding the components of net loss for each period presented.

We had net cash provided by operating activities of $128.5 million for the three months ended September 30, 2017, compared with $158.1 million for the same period in 2016. Please refer to Overview of Liquidity and Capital Resourcesbelow for additional discussion of our sources and uses of cash.

Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2017, was $164.5 million, compared with $205.1 million for the same period in 2016. Please refer to Non-GAAP Financial Measuresbelow for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net loss and net cash provided by operating activities to adjusted EBITDAX.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period before the effectseffect of derivative settlements, unless otherwise indicated.settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

28


The following table summarizes commodity price data, as well as the effectseffect of derivative settlements, for the thirdthree months ended September 30, 2022, June 30, 2022, and second quartersSeptember 30, 2021:
For the Three Months Ended
September 30, 2022June 30, 2022September 30, 2021
Oil (per Bbl):
Average NYMEX contract monthly price$91.56 $108.41 $70.56 
Realized price$92.66 $108.64 $69.30 
Effect of oil derivative settlements$(21.22)$(29.19)$(19.13)
Gas:
Average NYMEX monthly settle price (per MMBtu)$8.20 $7.17 $4.01 
Realized price (per Mcf)$7.58 $7.66 $5.12 
Effect of gas derivative settlements (per Mcf)$(2.00)$(1.69)$(1.23)
NGLs (per Bbl):
Average OPIS price (1)
$42.47 $50.05 $40.39 
Realized price$36.36 $42.08 $36.87 
Effect of NGL derivative settlements$(2.11)$(4.13)$(16.65)

(1)    Average OPIS price per barrel of 2017,NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Given the uncertainty surrounding (a) the ongoing conflict between Russia and Ukraine, (b) the economic and trade sanctions that certain countries have imposed on Russia, (c) production output from the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as well as“OPEC+”), and the third quarterpotential impacts of 2016:
 For the Three Months Ended
 September 30, 2017 June 30, 2017 September 30, 2016
Crude Oil (per Bbl):     
Average NYMEX contract monthly price$48.20
 $48.28
 $44.94
Realized price, before the effect of derivative settlements$45.20
 $44.30
 $38.81
Effect of oil derivative settlements$(0.73) $(0.94) $11.34
      
Natural Gas:     
Average NYMEX monthly settle price (per MMBtu)$3.00
 $3.18
 $2.81
Realized price, before the effect of derivative settlements (per Mcf)$2.96
 $2.99
 $2.71
Effect of natural gas derivative settlements (per Mcf)$0.83
 $0.64
 $0.27
      
NGLs (per Bbl): 
     
Average OPIS price (1)
$27.55
 $24.11
 $19.74
Realized price, before the effect of derivative settlements$22.40
 $19.71
 $16.58
Effect of NGL derivative settlements$(3.54) $(0.98) $(0.51)

(1)
Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 14% Natural Gasoline, 11% Normal Butane, and 6% Isobutane for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

Wethese issues on global commodity and financial markets, we expect futurebenchmark prices for oil, gas, and NGLs to continue to be volatile.remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result, which could include further inflation, supply chain disruptions, a continued rise in interest rates, and industry-specific impacts. In addition to supply and demand fundamentals, as a global commodity,commodities, the price ofprices for oil, isgas, and NGLs are affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. Oil markets have strengthened due to recent inventory drawdowns, but we expect oilOur realized prices to remain volatile due to uncertainty in global demand and easy access to new supply such as increases in oil production from US shale producers. Oil prices began to increase at the end of 2016 as a result of the Organization of Petroleum Exporting Countries (“OPEC”) and several non-OPEC exporting countries agreeing to cut production. While participating countries have largely adhered to agreed upon production cuts, uncertainty remains concerning whether these cuts willlocal sales points may also be sustained.

Natural gas pricing has improved over the last year, largely as a result of demand growth from gas fired power generation, gas exports to Mexico, and LNG exports. We expect prices to remain near current levelsaffected by infrastructure capacity in the near term as drilling rigs in operation increased through the first halfareas of 2017 leading to increased supply. We also expect prices to fluctuate with changes in demand resulting from the weather.

NGL prices have also improved over the last year due to oilour operations and natural gas price recovery, increased exports of ethane and propane, and new processing plants. We expect NGL prices to continue to benefit from increased demand from export and petrochemical markets while being offset by increased drilling activity.

beyond.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of October 26, 2017,27, 2022, and September 30, 2017:2022:
As of October 27, 2022As of September 30, 2022
NYMEX WTI oil (per Bbl)$83.78 $75.32 
NYMEX Henry Hub gas (per MMBtu)$5.14 $5.85 
OPIS NGLs (per Bbl)$33.81 $32.91 
 As of October 26, 2017 As of September 30, 2017
NYMEX WTI oil (per Bbl)$52.87
 $51.99
NYMEX Henry Hub gas (per MMBtu)$3.02
 $3.05
OPIS NGLs (per Bbl)$29.61
 $28.67
We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives.  Thederivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain of our senior executive officers and finance personnel. We make decisions about the amount of our expected production coveredthat we cover by derivatives is driven bybased on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our ability to enter into favorable derivative commodity contracts.approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in

some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil production.below which we are insulated from further price decreases. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and the caption titled to Commodity Price Risk in Overview of Liquidity and Capital Resourcesbelow for additional information regarding our oil, gas, and NGL derivatives.

29

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information. A detailed discussion follows.information for the three months ended September 30, 2022, and the preceding three quarters:

For the Three Months Ended
For the Three Months EndedSeptember 30,June 30,March 31,December 31,
September 30, June 30, March 31, December 31,2022202220222021
2017 2017 2017 2016
(in millions, except for production data)(in millions)
Production (MMBOE)10.7
 11.3
 12.1
 13.4
Production (MMBOE)12.7 13.3 13.8 14.6 
Oil, gas, and NGL production revenue$294.5
 $284.9
 $333.2
 $346.3
Oil, gas, and NGL production revenue$827.6 $990.4 $858.7 $852.4 
Oil, gas, and NGL production expense$122.7
 $124.4
 $138.0
 $151.9
Oil, gas, and NGL production expense$160.0 $165.6 $144.7 $143.3 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$134.6
 $153.2
 $137.8
 $171.6
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$145.9 $154.8 $159.5 $200.0 
Exploration$14.2
 $13.1
 $12.0
 $23.7
Exploration$14.2 $20.9 $9.0 $12.6 
General and administrative$27.9
 $28.5
 $29.2
 $33.3
General and administrative$28.4 $28.3 $25.0 $37.1 
Net income (loss)$(89.1) $(119.9) $74.4
 $(200.9)
Net incomeNet income$481.2 $323.5 $48.8 $424.9 

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics

For the Three Months Ended
For the Three Months EndedSeptember 30,June 30,March 31,December 31,
September 30, June 30, March 31, December 31,2022202220222021
2017 2017 2017 2016
Average net daily production equivalent (MBOE per day)116.0
 124.6
 134.4
 145.6
Average net daily equivalent production (MBOE per day)Average net daily equivalent production (MBOE per day)137.8 146.6 153.3 158.3 
Lease operating expense (per BOE)$4.81
 $4.11
 $3.82
 $3.67
Lease operating expense (per BOE)$5.64 $5.11 $4.25 $4.21 
Transportation costs (per BOE)$5.24
 $5.71
 $5.88
 $6.39
Transportation costs (per BOE)$2.87 $2.87 $2.74 $2.61 
Production taxes as a percent of oil, gas, and NGL production revenue4.2% 4.0% 4.2% 4.3%Production taxes as a percent of oil, gas, and NGL production revenue4.9 %5.1 %4.7 %4.8 %
Ad valorem tax expense (per BOE)$0.29
 $0.16
 $0.55
 $0.17
Ad valorem tax expense (per BOE)$0.93 $0.69 $0.58 $0.22 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)$12.61
 $13.52
 $11.39
 $12.81
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)$11.50 $11.60 $11.56 $13.74 
General and administrative (per BOE)$2.61
 $2.51
 $2.42
 $2.49
General and administrative (per BOE)$2.24 $2.12 $1.81 $2.55 

Note: Amounts may not calculate due to rounding.

30

A Three-Month and Nine-Month Overview of Selected Production and Financial Information, Including Trends
For the Three Months EndedAmount Change Between PeriodsPercent Change Between PeriodsFor the Nine Months EndedAmount Change Between PeriodsPercent Change Between Periods
September 30,June 30,September 30,September 30,
2022202220222021
Net production volumes: (1)
Oil (MMBbl)5.7 6.1 (0.5)(8)%18.3 20.2 (1.9)(9)%
Gas (Bcf)31.0 31.5 (0.6)(2)%93.8 77.1 16.7 22 %
NGLs (MMBbl)1.8 1.9 (0.1)(5)%5.9 3.8 2.1 56 %
Equivalent (MMBOE)12.7 13.3 (0.7)(5)%39.8 36.8 3.0 8 %
Average net daily production: (1)
Oil (MBbl per day)61.7 67.5 (5.8)(9)%66.9 73.9 (6.9)(9)%
Gas (MMcf per day)336.5 346.3 (9.9)(3)%343.7 282.5 61.2 22 %
NGLs (MBbl per day)20.1 21.4 (1.4)(6)%21.6 13.9 7.8 56 %
Equivalent (MBOE per day)137.8 146.6 (8.8)(6)%145.8 134.8 11.0 8 %
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue$525.9 $667.0 $(141.1)(21)%$1,800.3 $1,300.5 $499.7 38 %
Gas production revenue234.6 241.3 (6.8)(3)%645.9 327.0 319.0 98 %
NGL production revenue67.1 82.0 (15.0)(18)%230.5 118.1 112.4 95 %
Total oil, gas, and NGL production revenue$827.6 $990.4 $(162.8)(16)%$2,676.7 $1,745.5 $931.1 53 %
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense$71.5 $68.1 $3.3 5 %$198.2 $164.2 $34.0 21 %
Transportation costs36.4 38.3 (1.8)(5)%112.4 101.4 11.0 11 %
Production taxes40.2 50.0 (9.8)(20)%130.7 80.4 50.3 63 %
Ad valorem tax expense11.9 9.2 2.7 29 %29.0 16.2 12.8 79 %
Total oil, gas, and NGL production expense$160.0 $165.6 $(5.6)(3)%$470.2 $362.1 $108.1 30 %
Realized price:
Oil (per Bbl)$92.66 $108.64 $(15.98)(15)%$98.52 $64.50 $34.02 53 %
Gas (per Mcf)$7.58 $7.66 $(0.08)(1)%$6.88 $4.24 $2.64 62 %
NGLs (per Bbl)$36.36 $42.08 $(5.72)(14)%$39.04 $31.19 $7.85 25 %
Per BOE$65.27 $74.23 $(8.96)(12)%$67.23 $47.43 $19.80 42 %
Per BOE data: (1)
Oil, gas, and NGL production expense:
Lease operating expense$5.64 $5.11 $0.53 10 %$4.98 $4.46 $0.52 12 %
Transportation costs2.87 2.87 — — %2.82 2.75 0.07 3 %
Production taxes3.17 3.75 (0.58)(15)%3.28 2.18 1.10 50 %
Ad valorem tax expense0.93 0.69 0.24 35 %0.73 0.44 0.29 66 %
Total oil, gas, and NGL production expense (1)
$12.62 $12.41 $0.21 2 %$11.81 $9.84 $1.97 20 %
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$11.50 $11.60 $(0.10)(1)%$11.56 $15.61 $(4.05)(26)%
General and administrative$2.24 $2.12 $0.12 6 %$2.05 $2.03 $0.02 1 %
Derivative settlement loss (2)
$(14.69)$(18.03)$3.34 19 %$(14.95)$(13.05)$(1.90)(15)%
Earnings per share information (in thousands, except per share data): (3)
Basic weighted-average common shares outstanding123,195 121,9101,2851 %122,318 118,224 4,094 3 %
Diluted weighted-average common shares outstanding124,279 124,343(64)— %124,233 118,224 6,009 5 %
Basic net income (loss) per common share$3.91 $2.65 $1.26 48 %$6.98 $(3.29)$10.27 312 %
Diluted net income (loss) per common share$3.87 $2.60 $1.27 49 %$6.87 $(3.29)$10.16 309 %
31
 For the Three Months Ended September 30, Amount Change Between Periods Percent Change Between Periods For the Nine Months Ended September 30, Amount Change Between Periods Percent Change Between Periods
 2017 2016  2017 2016 
Net production volumes (1)
               
Oil (MMBbl)3.4
 4.3
 (0.9) (21)% 9.8
 12.6
 (2.7) (22)%
Gas (Bcf)29.1
 37.1
 (8.0) (22)% 97.0
 111.7
 (14.7) (13)%
NGLs (MMBbl)2.4
 3.6
 (1.2) (34)% 8.1
 10.7
 (2.6) (24)%
Equivalent (MMBOE)10.7
 14.2
 (3.5) (25)% 34.1
 41.9
 (7.8) (19)%
Average net daily production (1)
               
Oil (MBbl per day)37.1
 47.2
 (10.1) (21)% 36.1
 45.9
 (9.8) (21)%
Gas (MMcf per day)316.1
 403.0
 (86.9) (22)% 355.4
 407.8
 (52.4) (13)%
NGLs (MBbl per day)26.2
 39.5
 (13.3) (34)% 29.6
 39.0
 (9.4) (24)%
Equivalent (MBOE per day)116.0
 153.9
 (37.9) (25)% 124.9
 152.9
 (27.9) (18)%
Oil, gas, and NGL production revenue (in millions)               
Oil production revenue$154.2
 $168.6
 $(14.4) (9)% $450.7
 $436.0
 $14.7
 3 %
Gas production revenue86.3
 100.4
 (14.1) (14)% 289.2
 236.7
 52.5
 22 %
NGL production revenue54.0
 60.2
 (6.2) (10)% 172.7
 159.4
 13.3
 8 %
Total$294.5
 $329.2
 $(34.7) (11)% $912.6
 $832.1
 $80.5
 10 %
Oil, gas, and NGL production expense (in millions)               
Lease operating expense$51.4
 $46.5
 $4.9
 11 % $144.1
 $144.7
 $(0.6) — %
Transportation costs55.9
 88.4
 (32.5) (37)% 191.7
 254.8
 (63.1) (25)%
Production taxes12.4
 14.7
 (2.3) (16)% 37.8
 37.0
 0.8
 2 %
Ad valorem tax expense3.0
 2.9
 0.1
 3 % 11.5
 9.2
 2.3
 25 %
Total$122.7
 $152.5
 $(29.8) (20)% $385.1
 $445.7
 $(60.6) (14)%
Realized price (before the effect of derivative settlements)               
Oil (per Bbl)$45.20
 $38.81
 $6.39
 16 % $45.77
 $34.69
 $11.08
 32 %
Gas (per Mcf)$2.96
 $2.71
 $0.25
 9 % $2.98
 $2.12
 $0.86
 41 %
NGLs (per Bbl)$22.40
 $16.58
 $5.82
 35 % $21.36
 $14.91
 $6.45
 43 %
Per BOE$27.59
 $23.25
 $4.34
 19 % $26.76
 $19.87
 $6.89
 35 %
Per BOE data (1)
               
Production costs:               
Lease operating expense$4.81
 $3.29
 $1.52
 46 % $4.22
 $3.46
 $0.76
 22 %
Transportation costs$5.24
 $6.24
 $(1.00) (16)% $5.62
 $6.08
 $(0.46) (8)%
Production taxes$1.15
 $1.04
 $0.11
 11 % $1.11
 $0.88
 $0.23
 26 %
Ad valorem tax expense$0.29
 $0.21
 $0.08
 38 % $0.34
 $0.22
 $0.12
 55 %
General and administrative$2.61
 $2.31
 $0.30
 13 % $2.51
 $2.22
 $0.29
 13 %
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$12.61
 $13.70
 $(1.09) (8)% $12.48
 $14.78
 $(2.30) (16)%
Derivative settlement gain (2)
$1.23
 $4.06
 $(2.83) (70)% $0.86
 $7.31
 $(6.45) (88)%
Earnings per share information               
Basic net loss per common share$(0.80) $(0.52) $(0.28) (54)% $(1.21) $(7.78) $6.57
 84 %
Diluted net loss per common share$(0.80) $(0.52) $(0.28) (54)% $(1.21) $(7.78) $6.57
 84 %
Basic weighted-average common shares outstanding (in thousands)111,575
 78,468
 33,107
 42 % 111,366
 71,574
 39,792
 56 %
Diluted weighted-average common shares outstanding (in thousands)111,575
 78,468
 33,107
 42 % 111,366
 71,574
 39,792
 56 %


(1)
Amount and percentage changes may not calculate due to rounding.
(2)
Derivative settlements for the three and nine months ended September 30, 2017, and 2016, respectively, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

(1)    Amounts and percentage changes may not calculate due to rounding.
(2)    Derivative settlements for the three months ended September 30, 2022, and for the nine months ended September 30, 2022, and 2021, are included within the net derivative (gain) loss line item in the accompanying statements of operations.
(3)    Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.
Average net daily equivalent production for the three months ended September 30, 2022, decreased six percent sequentially, consisting of six percent decreases from both our Midland Basin and South Texas assets primarily due to the effects of delayed well completions which were largely related to the supply chain, and impacts to production associated with offset activity. Average net daily equivalent production for the nine months ended September 30, 2022, increased eight percent compared with the same period in 2021, driven by an increase of 46 percent from our South Texas assets which was the result of increased capital allocation to our Austin Chalk assets, and strong well performance.
We present certain information on a per BOE information because we use this informationbasis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis. Average net daily production for the threeanalysis and nine months ended September 30, 2017, decreased 25 percent and 18 percent, respectively, compared with the same periods in 2016. These decreases are primarily due to the divestitures of properties across our regions in the last half of 2016 and the first quarter of 2017, specifically the divestitures of our Raven/Bear Den and outside-operated Eagle Ford shale assets. When excluding production from all assets sold in 2016 and 2017, daily production from retained assets increased approximately seven percent and 11 percent for the three and nine months ended September 30, 2017, compared with the same periods in 2016, respectively, which is being driven primarily by the ramp up in our Midland Basin development program. Overall, we expect a decrease in production for full-year 2017 compared with full-year 2016. Please refer toComparison of Financial Results and Trends Between the Three Months and Nine Months Ended September 30, 2017, and 2016 below for additional discussion.

Changes in production volumes, revenues, and costs reflect the macro-economic effects on commodity prices and our transitioning portfolio. Our realized price before the effects of derivative settlements on a per BOE basis for the threedecreased $8.96 sequentially as a result of decreases in oil and nine months ended September 30, 2017, increased 19 percentNGL benchmark prices. The impact on oil, gas, and 35 percent, respectively, compared with the same periods in 2016. Commodity prices were at multi-year lows in early 2016, began to recoverNGL production revenues resulting from these decreases was partially offset by a decrease in the second half of 2016, and fluctuated throughout the first nine months of 2017. For the three and nine months ended September 30, 2017, we had $1.23 and $0.86 per BOE gainsloss on the settlement of our commodity derivative contracts respectively, which compares with gains of $4.06 and $7.31$3.34 per BOE for the three and nine months ended September 30, 2016, respectively. Despite commodity prices being low in the first half of 2016, we have experienced a slight increase in ourBOE. Our realized price after the effect of derivative settlements for the three and nine months ended September 30, 2017, compared with the same periods in 2016.

Lease operating expense (“LOE”) on a per BOE basis increased 46 percent$19.80 YTD 2022-over-YTD 2021 as a result of increased benchmark commodity prices. The positive impact on oil, gas, and 22 percent, respectively, for the three and nine months ended September 30, 2017, compared with the same periods in 2016. TheNGL production revenues resulting from this increase was partially offset by an increase in the loss on the settlement of our commodity derivative contracts of $1.90 per BOE.
LOE on a per BOE basis increased 10 percent sequentially and 12 percent YTD 2022-over-YTD 2021. These increases were the result of increased workover activity and increased service provider costs which have been impacted by inflation. The sequential quarterly increase was also driven primarily by a five percent decrease in total net equivalent production volumes. For the divestiture of our outside-operated Eagle Ford shale assets in the first quarter of 2017, which had lower average lifting costs, as well as higher unanticipated LOE costs in our operated Eagle Ford shale program during the three months ended September 30, 2017. Wefull-year 2022, we expect LOE on a per BOE basis to be higher in 2017increase, compared with 20162021, due to increases in service provider costs and workover activity, which we expect to be partially offset by increasing activity in the changeAustin Chalk, where operating costs are lower than in the Midland Basin. We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our asset baseoverall production mix, timing of workover projects, and increasing oilindustry activity, all of which impact total LOE.
Transportation costs on a per BOE basis remained flat sequentially and increased three percent YTD 2022-over-YTD 2021. The YTD 2022-over-YTD 2021 increase was the result of a 46 percent increase in net daily equivalent production volumes from our South Texas assets which has higher LOE,was partially offset by transportation contract cost reductions. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets. For the full-year 2022, we expect transportation costs on an absolute basis to increase compared with 2021, as a percentageresult of increased activity in South Texas in 2022, where we incur a majority of our total product mix. However, LOE may also vary by quarter depending upontransportation costs. The impact of the levelexpected increase in net equivalent production volumes from our South Texas assets is expected to outweigh the impact of workover activity, total production, and our overall product mix.transportation contract cost reductions, resulting in an expected increase in transportation costs on a per BOE basis for the full-year 2022, compared with 2021.

TransportationProduction tax expense on a per BOE basis decreased 1615 percent sequentially as a result of decreases in realized prices, and eightincreased 50 percent respectively, forYTD 2022-over-YTD 2021, as a result of increases in realized prices during the three and nine months ended September 30, 2017, compared with the same periods in 2016, primarily due to the sale of our outside-operated Eagle Ford shale assets in the first quarter of 2017. In general, we expect transportation costs on a per BOE basis to decrease in 2017 as our Midland Basin assets become a larger portion of our production mix. The majority of our Midland Basin production is sold at the wellhead under current contracts, and therefore, there is minimal transportation expense separately recorded on the accompanying statements of operations.

Production taxes on a per BOE basis increased 11 percent and 26 percent, respectively, for the three and nine months ended September 30, 2017, compared with the same periods in 2016, due to an increase in our realized price before the effect of derivative settlements, which was partially offset by a decrease in our production tax rate.period. Our overall production tax rate for the three and nine months ended September 30, 2017,2022, was 4.24.9 percent, and 4.1 percent, respectively, compared with 4.55.1 percent and 4.4 percent, respectively, for the same periods in 2016. This decrease in our company-wide production tax rate is primarily a result of divesting our Raven/Bear Denthree months ended June 30, 2022, and other Rocky Mountain assets, which were taxed at higher rates than our Texas assets.4.6 percent for the nine months ended September 30, 2021. We generally expect production tax expense to trendcorrelate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.

Ad valorem tax expense on a per BOE basis increased 3835 percent sequentially and 5566 percent respectively for the three and nine months ended September 30, 2017, compared with the same periods in 2016,YTD 2022-over-YTD 2021 as a result of changes in our asset and production base and increased commodity price assumptions used in 2017 property tax valuations. The majorityto the expected value assessments of our ad valorem tax expense is related to our Texas properties. As a result of acquiring producing properties, which are driven by increases in Texas and divesting producing propertiescommodity prices. The sequential quarterly increase was further impacted by a decrease in our Rocky Mountain region, and with higher commodity prices usedtotal net equivalent production volumes. We anticipate volatility in the 2017 valuations than in 2016 valuations, we expect ad valorem tax expense on an absolute and per BOE basis to be higher for full-year 2017 compared to 2016.

General and administrative (“G&A”) expense on a per BOE basis increased 13 percent for both the three and nine months ended September 30, 2017, compared with the same periods in 2016, due to the decrease in production volumes as a result of recent

divestitures. We expect G&A expense on an absolute basis to remain relatively flat in 2017 compared with 2016 as reduced headcount is expected to be offset by increases in base and short-term incentive compensation. However, we expect an overall increase in G&A expense on a per BOE basis in 2017 due to the decrease in production volumes.
valuation of our producing properties changes.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis remained flat sequentially and decreased eight26 percent and 16 percent, respectively, for the three and nine months ended September 30, 2017, compared with the same periods in 2016,YTD 2022-over-YTD 2021 as a result of divested assets, specificallyincreased estimated proved reserves at year-end 2021 and increased activity in our higher cost Raven/Bear Den assets sold at the end of 2016,Austin Chalk program, which has lower DD&A rates compared with our outside-operated Eagle Ford shale assets that were held for sale prior to being sold in the first quarter of 2017, and our Divide County, North Dakota, assets that were classified as held for sale during the first quarter of 2017 and for a portion of the second quarter of 2017. These assets were not depleted while classified as held for sale.Midland Basin assets. Our DD&A rate fluctuates as a result of impairments, planneddivestiture activity, carrying cost funding and closed divestitures,sharing arrangements with third parties, changes in our production mix, and changes in the mix of our production and the underlyingtotal estimated proved reserve volumes. In general, weWe expect DD&A expense per BOE and DD&A expense on an absolute basis to decrease in 2022, compared with 2021, primarily as a result of increased estimated proved reserves and increased activity in our Austin Chalk program.
General and administrative (“G&A”) expense on a per BOE basis increased six percent sequentially as a result of decreased total net equivalent production volumes, and remained flat YTD 2022-over-YTD 2021. Despite inflationary pressures, for the full-year 2022 we currently expect G&A expense to be lower for full-year 2017 than full-year 2016 duedecrease slightly on an absolute basis and to selling our higher cost Raven/Bear Den assets in late 2016decrease on a per BOE basis, compared with
32

2021. However, G&A expense could fluctuate based on the results of the Company’s full year financial and the impact of large asset packages held for sale during the first quarter of 2017.operational performance metrics.

Please refer toComparison of Financial Results and Trends Between the Three Months Ended September 30, 2022, and June 30, 2022, and Between the Nine Months Ended September 30, 2017,2022, and 2016 2021 below for additional discussion onof operating expenses.
Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for discussion on our basic and diluted net loss per common share calculations. Our basic and diluted weighted-average common share count increased for the three and nine months ended September 30, 2017, compared with the same periods in 2016, due primarily to public and private common stock offerings made in the last half of 2016.

Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2022, and June 30, 2022, and Between the Nine Months Ended September 30, 2017,2022, and 20162021

Oil, gas, and NGLAverage net daily equivalent production, production revenues,revenue, and production costsexpense

Sequential Quarterly Changes. The following table presents the regional changes in our oil, gas, and NGLaverage net daily equivalent production, production revenues,revenue, and production costsexpense, by area, between the three and nine months ended September 30, 2017, and 2016:
 
Average Net Daily Production
Increase (Decrease)
 
Production Revenues
Increase (Decrease)
 
Production Costs
Increase (Decrease)
 Three Months EndedNine Months Ended Three Months EndedNine Months Ended Three Months EndedNine Months Ended
 (MBOE/d) (in millions) (in millions)
Permian21.6
18.2
 $87.3
$228.4
 $23.2
$56.1
South Texas & Gulf Coast(40.1)(28.4) (66.0)(35.3) (30.5)(57.3)
Rocky Mountain(19.4)(17.7) (56.0)(112.6) (22.5)(59.4)
Total(37.9)(27.9) $(34.7)$80.5
 $(29.8)$(60.6)

For the three months ended September 30, 2017, compared with the same period in 2016, the 252022, and June 30, 2022:
Net Equivalent Production
Decrease		Production Revenue
Decrease		Production Expense Increase (Decrease)
(MBOE per day)(in millions)(in millions)
Midland Basin(5.1)$(127.5)$(8.3)
South Texas(3.7)(35.3)2.7 
Total(8.8)$(162.8)$(5.6)

Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes decreased six percent, consisting of six percent decreases from both our Midland Basin and South Texas assets. Our realized oil, gas, and NGL prices decreased 15 percent, one percent, and 14 percent, respectively. The 12 percent decrease in total realized price per BOE, combined with a six percent decrease in average net daily equivalent production volumes, primarily due to recent divestitures, was partially offset byresulted in a 19 percent increase in realized prices on a per BOE basis resulting in an overall 1116 percent decrease in oil, gas, and NGL production revenues. Forrevenue. Total production expense decreased three percent, primarily driven by a decrease in production tax expense, partially offset by increases in LOE and ad valorem tax expense.
YTD 2022-over-YTD 2021 Changes. The following table presents changes in our average net daily equivalent production, production revenue, and production expense, by area, between the nine months ended September 30, 2017, compared with the same period in 2016, the 352022, and 2021:
Net Equivalent Production Increase (Decrease)Production Revenue
Increase		Production Expense
Increase
(MBOE per day)(in millions)(in millions)
Midland Basin(8.7)$416.7 $57.4 
South Texas19.7 514.4 50.7 
Total11.0 $931.1 $108.1 

Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes increased eight percent, consisting of an increase in realized prices on a per BOE basis wasof 46 percent from our South Texas assets partially offset by a 19 percent decrease in net equivalent production volumes, primarily due to recent divestitures, resulting in aof 10 percent increasefrom our Midland Basin assets. Realized prices for oil, gas, and NGLs increased 53 percent, 62 percent, and 25 percent, respectively. As a result of increases in benchmark commodity prices and production volumes, oil, gas, and NGL production revenues. Production costs for the three and nine months ended Septemberrevenue increased 53 percent. Total production expense increased 30 2017, compared with the same periods in 2016, decreased 20 percent, and 14 percent, respectively, due to the decrease in net equivalent production volumes,primarily as discussed above. Partially offsetting the decreasea result of increases in production volumes, revenues,tax expense and costs in our South Texas & Gulf Coast and Rocky Mountain regions due to recent divestitures was an increase in production volumes, revenues, and costs in our Permian region in 2017 due to increased drilling and completion activity in our Midland Basin development program. LOE.
Please refer to A Three-Month and Nine-Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion

Net gain (loss) on divestiture activity
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$145.9 $154.8 $460.2 $574.4 
33

 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Net gain (loss) on divestiture activity$(1.9) $22.4
 $(131.6) $3.4
DD&A expense decreased six percent sequentially and 20 percent YTD 2022-over-YTD 2021. The sequential quarterly decrease was primarily driven by a five percent decrease in net equivalent production volumes, and the YTD 2022-over-YTD 2021 decrease was driven by increased estimated proved reserves at year-end 2021 and increased activity in our Austin Chalk program, which has lower DD&A rates compared with our Midland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion of DD&A expense on a per BOE basis.

Exploration
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
Geological, geophysical, and other expenses$6.8 $13.7 $21.8 $5.3 
Overhead7.4 7.2 22.3 21.4 
Total$14.2 $20.9 $44.1 $26.7 

Note: Prior periods have been adjusted to conform to the current period presentation.
Exploration expense decreased 32 percent sequentially and increased 65 percent YTD 2022-over-YTD 2021, as a result of unsuccessful exploration efforts outside of our core areas of operations which primarily impacted the three months ended June 30, 2022. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.
Impairment
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
Impairment$1.1 $4.4 $6.5 $26.3 
Impairment expense recorded during the periods presented consists entirely of unproved property abandonments and impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks. Impairment expense decreased YTD 2022-over-YTD 2021, as a result of fewer actual and anticipated lease expirations and title defects.
We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or title defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.
Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as of October 27, 2022, we do not expect any material oil and gas property impairments in the fourth quarter of 2022 resulting from commodity price impacts. We expect abandonment and impairment expense related to unproved properties to decrease for the full-year 2022, compared with 2021.
General and administrative
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
General and administrative$28.4 $28.3 $81.7 $74.9 
G&A expense increased nine percent YTD 2022-over-YTD 2021 as a result of increased compensation expense. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for additional discussion of G&A expense on a per BOE basis.
34

Net derivative (gain) loss
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
Net derivative (gain) loss$(137.6)$104.2 $385.2 $924.2 
Net derivative (gain) loss is a result of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. The $131.6 million net loss on divestiture activity recordedderivative gain for the three months ended September 30, 2022, resulted from decreases in oil and NGL benchmark prices. The net derivative losses for the three months ended June 30, 2022, and for the nine months ended September 30, 2017, was primarily the result of a $526.5 million write-down on our retained Divide County, North Dakota, assets previously held for sale, which was partially offset by a $396.8 million net gain recorded on the sale of our outside-operated Eagle Ford shale assets during the first quarter of 2017.

The $22.4 million net gain on divestiture activity recorded for the three months ended September 30, 2016, was a result of closing divestitures2022, and 2021, resulted from increases in our Rocky Mountain and Permian regions during the third quarter of 2016. Certain of these sold assets were written down in the first quarter of 2016 and subsequently written up in the second quarter of 2016 based on changes in the estimated fair value less selling costs resulting in a small net gain for the nine months ended September 30, 2016.

benchmark commodity prices. Please refer to Note 310 - Divestitures, Assets Held for Sale, and AcquisitionsDerivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Other operating expense, net
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
Other operating expense, net$1.2 $1.1 $2.6 $44.7 
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$134.6
 $194.0
 $425.6
 $619.2

DD&AOther operating expense, decreased 31 percent for both the three and nine months ended September 30, 2017, compared with the same periods in 2016, due to the decline in our production volumes and the impact of assets sold and assets held for sale. Please refer to the section A Three-Month and Nine-Month Overview of Selected Production and Financial Information, Including Trends above for further discussion of DD&A expense on a per BOE basis.

Exploration
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Exploration$14.2
 $13.5
 $39.3
 $41.9
Exploration expense remained relatively flat for the three and nine months ended September 30, 2017, compared with the same periods in 2016. We expect our exploration expense to be lower for the full-year 2017 as compared to the full-year 2016. However, exploration expense may also vary by quarter depending upon exploratory dry hole expense.

Impairment of proved properties and abandonment and impairment of unproved properties
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Impairment of proved properties$—
 $8.0
 $3.8
 $277.8
Abandonment and impairment of unproved properties$—
 $3.6
 $0.2
 $5.9


For the nine months ended September 30, 2016, we impaired proved properties early in the year, primarily in our outside-operated Eagle Ford shale program, as a result of continued commodity price declines, and we allowed certain leases to expire. We expect proved property impairments to occur more often in periods of declining or depressed commodity prices, and unproved property impairments to fluctuate with the timing of lease expirations, unsuccessful exploration activities, and changing economics associated with volatile commodity prices. Additionally, changes in drilling plans, downward engineering revisions, or unsuccessful exploration efforts may result in proved and unproved property impairments. Any amount of future impairment is difficult to predict, but based on updated commodity price assumptions as of October 26, 2017, we do not expect any material impairments in the fourth quarter of 2017.

General and administrative
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
General and administrative$27.9
 $32.7
 $85.6
 $93.1

G&A expense decreased 15 percent and eight percent for the three and nine months ended September 30, 2017, compared with the same periods in 2016 primarily due to lower compensation expense resulting from decreased headcount. Please refer to the section A Three-Month and Nine-Month Overview of Selected Production and Financial Information, Including Trends above for further discussion of G&A expense on an absolute and per BOE basis.

Net derivative (gain) loss
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Net derivative (gain) loss$80.6
 $(28.0) $(89.4) $121.1

We recognized an $80.6 million derivative loss for the three months ended September 30, 2017, due largely to a $72.6 million decrease in the fair value of contracts settling subsequent to September 30, 2017. Additionally, we recognized an $8.0 million loss on contracts that settlednet, recorded during the third quarter of 2017,2021 related to legal settlements, including the settlement of the SPM NAM LLC et al. case. Please refer to Legal Proceedings in Part I, Item 3 of our 2021 Form 10-K for additional discussion.
Interest expense
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
Interest expense$(22.8)$(35.5)$(97.7)$(120.3)
Interest expense decreased 36 percent sequentially and 19 percent YTD 2022-over-YTD 2021 as a result of the reduction in the aggregate principal amount of our Senior Notes through various transactions in 2021 and 2022, including the redemption of our 2024 Senior Notes on February 14, 2022, and the redemption of our 2025 Senior Secured Notes on June 17, 2022. As a result of these transactions, we expect interest expense to decrease for the full-year 2022, compared with 2021. Total interest expense can vary based on the timing and amount of borrowings under our revolving credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report and Overview of Liquidity and Capital Resources below for additional discussion.
Loss on extinguishment of debt
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions)
Loss on extinguishment of debt$— $(67.2)$(67.6)$(2.1)
The redemption of our 2025 Senior Secured Notes on June 17, 2022, resulted in a net loss on extinguishment of debt of $67.2 million, which had a fair valueincluded $33.5 million of $21.1premium paid, $26.3 million at June 30, 2017,of accelerated unamortized debt discount, and settled for $13.1 million. We recognized a $24.6$7.4 million gain on contract settlements throughof accelerated unamortized deferred financing costs.
The Tender Offer and 2022 Senior Notes Redemption completed during the second quarter of 2017 and recorded a $145.4 million increase in the fair value of remaining contracts as of June 30, 2017, resulting2021 resulted in a year-to-date net derivative gain of $89.4 million.
We recognized a $28.0 million derivative gain for the three months ended September 30, 2016, due to a $15.9 million gain on contracts that settled during the third quarter of 2016, which had a fair value of $41.6 million at June 30, 2016, and settled for $57.5 million. Additionally, during the third quarter of 2016, we recorded a $12.1 million increase in fair value of contracts settling subsequent to September 30, 2016. We recognized a $121.1 million derivative loss for the nine months ended September 30, 2016, driven largely by a $117.0 million mark-to-market loss on remaining contracts asextinguishment of September 30, 2016, resulting from the increase in commodity strip prices in the second halfdebt of 2016. Contracts settled$2.1 million, which included $1.5 million of accelerated unamortized deferred financing costs and $0.6 million of net premiums paid during the nine months ended September 30, 2016, had a fair value of $310.3 million at December 31, 2015, and settled at a $4.1 million loss.

2021. Please refer to Note 105 - Derivative Financial InstrumentsLong-Term Debt in Part I, Item 1 of this report for additional information.

Gain (loss) on extinguishmentdiscussion of debtthese transactions.
35

 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Gain (loss) on extinguishment of debt$—
 $—
 $—
 $15.7
Income tax (expense) benefit

For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30,
2022		September 30, 2022September 30, 2021
(in millions, except tax rate)
Income tax (expense) benefit$(119.4)$(86.7)$(219.0)$0.1 
Effective tax rate19.9 %21.1 %20.4 %— %
For the nine months ended September 30, 2016, we recorded a $15.7 million net gain on the early extinguishment of a portion of our Senior Notes during the first quarter of 2016, which included approximately $16.4 million associated with the discount

realized upon repurchase, slightly offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional information.

Interest expense
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Interest expense$(44.1) $(47.2) $(135.6) $(112.3)

The seven percentsequential quarterly decrease in interest expense for three months ended September 30, 2017, compared with the same period in 2016effective tax rate is due primarily to $10.0 million paid during the third quarter of 2016 to terminate a second lien facility that was no longer necessary to fund the Rock Oil Acquisition. The 21 percent increase in interest expense for the nine months ended September 30, 2017, compared with the same period in 2016, was primarily due to the additional debt issued in 2016effect of recorded discrete adjustments related to excess tax benefits from stock-based compensation awards which also resulted in an increase in our weighted-average interest rate. Please referwere partially offset by discrete adjustments related to Note 5 - Long-Term Debt in Part I, Item Icompensation limits for certain covered individuals. Additionally, as a result of commodity price increases during 2022, compared with 2021, and cumulative financial statement income exceeding cumulative financial statement losses over the prior three years, we anticipate that the valuation allowance recorded against the derivative deferred tax asset as of September 30, 2022, will be reversed at year-end 2022. The effect of this report and Overview of Liquidity and Capital Resourcesbelow for additional information.

Income tax benefit
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions, except tax rate)
Income tax benefit$39.3
 $23.7
 $65.8
 $314.5
Effective tax rate30.6% 36.7% 32.8% 36.1%

The decreaseanticipated reversal is included in the effective tax rate for the three and nine months ended September 30, 2017,2022.
The YTD 2022-over-YTD 2021 increase in the effective tax rate was primarily due to the effect of higher forecast income for the year ended December 31, 2022, compared with the same periods in 2016, was primarilyamount of forecast net income for the resultfull-year 2021 as of recording a discrete expense inSeptember 30, 2021.
The tax rates for each period presented reflect the third quartereffect of 2017 relating to an adjustment to record anvaluation allowance adjustments, the proportional effects of excess tax deficiencybenefits from stock-based compensation awards, and limits on expensing of certain covered individual’s compensation. Based on current projections, we estimate that between six percent and eight percent of full-year 2022 income tax expense will be current. During the settlementnine months ended September 30, 2022, we made estimated federal income tax payments of share-based payment awards. This reduction$10.0 million.
Changes in federal income tax laws or enactment of proposed legislation to increase the corporate tax rate and eliminate or reduce certain oil and gas industry deductions could have a material impact on our effective tax rate and current tax expense. The enactment of the tax benefit was partially offset by state apportionment changes dueInflation Reduction Act on August 16, 2022, is currently not expected to divestinghave a material effect on our outside-operated Eagle Ford shale assets and a decrease in valuation allowances due to projected utilization of various state net operating losses based upon our decision in the third quarter of 2017 that recognition was appropriate. This compares with an increase in valuation allowances in 2016 correlating from various projected state net operating losses, which decreased the 2016 effective tax rate. consolidated financial statements.
Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, and our current liquidity, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future.while continuing to meet our current financial obligations. We expectcontinue to manage the duration and level of our drilling and completion service commitments in order to maintain the flexibility with regard to adjust our activity level and capital expenditures during periods of prolonged weak commodity prices or to respond should commodity prices recover further.

expenditures.
Sources of Cash

We currently expectFor the nine months ended September 30, 2022, our 2017 capital program was funded with cash flows from operating activities and we expect that to be funded bycontinue for the remainder of 2022. As of September 30, 2022, our cash and cash equivalents balance was $498.4 million, which was an increase of $231.3 million from our cash and cash equivalents balance as of June 30, 2022. Although we expect cash flows from operations and proceeds from the divestiture of our outside-operated Eagle Ford shale assets during the first quarter of 2017. As of September 30, 2017, our cash balance totaled $441.4 million, which combined with our $924.8 million of available borrowing capacity under our Credit Agreement, resulted in $1.4 billion in liquidity.

Although we anticipate cash flows from operations and divestiture proceeds willto be sufficient to fund our expected 20172022 capital program, we may also elect to borrowuse borrowings under our Credit Agreement and/revolving credit facility or raise funds through new debt or equity financingsofferings or from other sources. Further, we may enter into additional carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. See Credit Agreement below for discussionsources of the reduction in our borrowing base in early 2017. Our borrowing base could be further reduced as a result of lower commodity prices, divestitures of proved properties, or newly issued debt.financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly-issuednewly issued securities may have rights, preferences, or privileges senior to those of certain existing stockholders. Any future downgrades in our credit ratings could make it more difficultstockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or expensive for us to borrow

additional funds.development programs. All of our sources of liquidity can be impactedaffected by the general conditionconditions of the broader economy, and byforce majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which affect us and our industry.

Our credit ratings affect the availability of and cost for us to borrow additional funds. Three major credit rating agencies have upgraded our credit ratings during 2022, reflecting our top-tier assets and operational performance, the redemption of our 2024 Senior Notes, and our strong liquidity profile, among other factors. Most recently, one major credit rating agency upgraded our credit rating upon our announcement of the Stock Repurchase Program in September 2022, citing our strong operational performance, ability to consistently generate cash flows with proceeds used to reduce gross debt, strong liquidity profile, and our use of financial derivative instruments as part of our financial risk management program. The credit rating agencies have also cited our priorities of improving our leverage metrics and continuing to reduce total debt, which we have achieved through the redemption of our 2025 Senior Secured Notes, and our expected ability to generate meaningful cash flows, among other reasons for the rating upgrades.
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We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Please refer to Note 10 - Derivative Financial Instrumentsin Part I, Item 1 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts.
Credit Agreement
Proposals to reformOn August 2, 2022, we entered into the Internal Revenue Code of 1986, as amended,Credit Agreement which include eliminating or reducing current tax deductions for intangible drilling costs, depreciation of equipment acquisition costs, domestic production activities, percentage depletion, and other deductions that reduce our taxable income, continue to be discussed by Congress. Although we believe this possibility has decreased with the recent congressional discussions on tax reform, should future legislation eliminate these deductions we would expect a reduction in net operating cash flows over time, thereby reducing funding available for our exploration and development capital programs, as well as funding available to our peers in the industry for similar programs. If enacted, reductions in available deductions could have a significant adverse effect on drilling in the United Statesprovides for a number of years.

Credit Agreement

Our Credit Agreement provides forsenior secured revolving credit facility with a maximum loan amount of $3.0 billion, an initial borrowing base of $2.5 billion, and has a maturity dateinitial aggregate lender commitments totaling $1.25 billion. As of December 10, 2019. On March 31, 2017, we entered into a Ninth Amendment to the Credit Agreement. Pursuant to the Ninth Amendment, and as part of the regular, semi-annual borrowing base redetermination process,September 30, 2022, the borrowing base and aggregate lender commitments were reduced to $925 million. This expected decrease was primarily due tounder the sale of our outside-operated Eagle Ford shale assets in the first quarter of 2017 and the decrease in the value of our proved reserves at December 31, 2016. Additionally, as part of the Ninth Amendment, we are now able to enter into derivative contracts for an increased percentage of projected production volumes. We had a zero balance on our credit facility as of September 30, 2017, and as of the filing of this report. As of the filing of this report, the second semi-annual redetermination for 2017 was in progress and is expected to be completed prior to year-end.Credit Agreement remained unchanged. No individual bank that is a party to ourparticipating in the Credit Agreement represents more than 10 percent of the aggregate lender commitments. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

commitment. We must comply with certain financial and non-financial covenants under the Credit Agreement, including covenants limiting dividend payments and requiring us to maintain certain financial ratios, as defined byterms of the Credit Agreement. Certain financial covenants under the Credit Agreement require, as of the last day of each fiscal quarter, our (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of September 30, 2017,2022, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion, as well as the caption Non-GAAP Financial Measuresbelow forpresentation of the calculationoutstanding balance, total amount of adjusted EBITDAXletters of credit, and reconciliationsavailable borrowing capacity under the Credit Agreement as of net lossOctober 27, 2022, September 30, 2022, and net cash provided by operating activities to adjusted EBITDAX.
December 31, 2021.
We had minimalno revolving credit facility activityborrowings during the three and nine months ended September 30, 2017, due to our significant cash balance resulting from the divestiture of our Raven/Bear Den assets in December 2016 and proceeds received from the sale of our outside-operated Eagle Ford shale assets during the first quarter of 2017.2022. Our daily weighted-average revolving credit facility debt balance was approximately $156.0 million and $239.7 million for the three and nine months ended September 30, 2016, respectively.2021, was $134.6 million. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, and the amount of our capital expenditures, including acquisitions, all impact the amount we have borrowedborrow under our revolving credit facility.

Weighted-Average Interest and Weighted-Average Borrowing Rates

Our weighted-average interest rates includerate includes paid and accrued interest, fees on the unused portion of the credit facility’s aggregate commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs, andcosts. Our weighted-average interest rate was impacted by the non-cash amortization of the discount related to our 2025 Senior Secured Notes and our 2021 Senior Secured Convertible Notes for the Senior Convertible Notes.periods during which they were outstanding. Our weighted-average borrowing rates includerate includes paid and accrued interest only.


The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the threeperiods presented:
For the Three Months EndedFor the Nine Months Ended
September 30, 2022June 30, 2022September 30, 2022September 30, 2021
Weighted-average interest rate7.0 %8.1 %7.8 %7.7 %
Weighted-average borrowing rate6.4 %7.1 %7.0 %6.7 %
Our weighted-average interest rates and nine months ended September 30, 2017,our weighted-average borrowing rates decreased sequentially, due to the redemption of the 2025 Senior Secured Notes on June 17, 2022. We expect our weighted-average interest rates and 2016:weighted-average borrowing rates to decrease for the full-year 2022 compared with 2021, primarily as a result of the redemption of our 2025 Senior Secured Notes.
 For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Weighted-average interest rate6.3% 6.2% 6.5% 6.1%
Weighted-average borrowing rate5.7% 5.7% 5.8% 5.6%

TheOur weighted-average interest rate and weighted-average borrowing rate remained flat forare impacted by the three months ended September 30, 2017, compared withoccurrence and timing of long-term debt issuances and redemptions and the same period in 2016, and increased foraverage outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rates are impacted by the nine months ended September 30, 2017, compared withfees paid on the same period in 2016, largely due to the issuanceunused portion of the Senior Convertible Notes and 2026 Notes in the third quarter of 2016. Further impacting these rates is the timing and amount of Senior Notes redemptions, changes in our aggregate lender commitment amount on our credit facility, and the average balance on our credit facility.commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the discount realized or premium paid upon repurchase, or the acceleration of unamortized deferred financing costs expensedand unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2021 Senior Secured Convertible Notes were retired upon repurchase. The rates also do not reflectmaturity on July 1, 2021, the fee paid to terminate an unused second lien facility in2024 Senior Notes were redeemed on February 14, 2022, and the third quarter2025 Senior Secured Notes were redeemed on June 17, 2022. After these dates, the weighted-average interest rate was no longer impacted by the non-cash amortization of 2016. Please refer to Note 5 - Long-Term Debt in Part I, Item 1deferred financing costs, or for the 2021 Senior Secured Convertible Notes and the 2025 Senior Secured Notes, the non-cash amortization of this report for additional discussion.

the discounts.
Uses of Cash
We use cash for the acquisition,development, exploration, and developmentacquisition of oil and gas properties andproperties; for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest.interest; and for repurchases of shares of our common stock under the Stock Repurchase Program. Expenditures for the acquisition,development, exploration, and developmentacquisition of oil and gas properties are the primary use of our capital resources. During the nine months ended September 30, 2017,2022, we spent $712.4approximately $591.8 million on capital expenditures and on acquiring proved and unproved oil and gas properties.expenditures. This amount differs from the costs incurred amount whichof $677.4 million for the nine months ended
37

September 30, 2022, as costs incurred is an accrual-based andamount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing, and financing activities, and our ability to assimilate acquisitions and execute our drilling program.development program, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes inare necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. Our 2022 capital program is expected to be between $870.0 million and $900.0 million. We will continue to monitor the economic environment through the remainder of the year and adjust our activity level as warranted.
We may from time to time repurchase certain amountsshares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, and/or through exchanges for other securities.securities, or a combination of both. Such repurchases or exchangesredemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or exchangesredemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.
On September 7, 2022, we announced that our Board of Directors approved the Stock Repurchase Program authorizing us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2024. We intend to fund repurchases from available working capital and cash provided by operating activities. Stock repurchases may also be funded with borrowings under the Credit Agreement. The timing, as well as the number and value of our shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. During the three months ended September 30, 2022, we repurchased and subsequently retired 452,734 shares of our common stock at a cost of $20.2 million, and as of September 30, 2022, $479.8 million remained available under the Stock Repurchase Program for repurchases of our common stock. Please refer to Note 53 - Long-Term DebtEquity in Part I, Item 1 of this report for additional discussion of previously repurchased Senior Notes.discussion. The Stock Repurchase Program terminates and supersedes the August 1998 authorization to repurchase common stock, under which 3,072,184 shares remained available for repurchase prior to termination.
AsOn February 14, 2022, we redeemed all of the filing$104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes at a redemption price equal to 100 percent of the principal amount of the 2024 Senior Notes on the date of redemption, plus accrued and unpaid interest. On June 17, 2022, we redeemed all of the $446.7 million of aggregate principal amount outstanding of our 2025 Senior Secured Notes at a redemption price equal to 107.5 percent of the principal amount of the 2025 Senior Secured Notes on the date of the redemption. We paid total consideration of $480.2 million, including premium, and paid $18.9 million of accrued interest related to the 2025 Senior Secured Notes. During the second quarter of 2021, we issued our 2028 Senior Notes and used the net cash proceeds of $392.8 million to repurchase $193.1 million and $172.3 million of outstanding principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, through the Tender Offer, and to redeem the remaining $19.3 million of 2022 Senior Notes then outstanding through the 2022 Senior Notes Redemption. We paid total consideration of $385.3 million, including net premiums, and paid $5.2 million of accrued interest related to the 2022 Senior Notes and 2024 Senior Notes. The 2021 Senior Secured Convertible Notes matured on July 1, 2021, and on that day, we used borrowings under our revolving credit facility to retire at par the outstanding principal amount of $65.5 million. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiatedfor additional discussion. These transactions subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this programwere completed as part of the allocation of our capital. We currently do not planstrategy for 2022 to repurchase any outstanding shares of common stock during 2017.reduce absolute debt and improve our leverage metrics.

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2017,2022, and 20162021

The following tables present changes in cash flows between the nine months ended September 30, 2017,2022, and 2016,2021, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our condensed consolidatedaccompanying statements of cash flows in Part I, Item 1 of this report.


Operating activities
For the Nine Months Ended September 30,Amount Change Between Periods
20222021
(in millions)
Net cash provided by operating activities$1,398.0 $730.1 $667.9 
 For the Nine Months Ended 
 September 30,		 Amount Change Between Periods Percent Change Between Periods
 2017 2016  
 (in millions)  
Net cash provided by operating activities$370.6
 $415.0
 $(44.4) (11)%

CashNet cash provided by operating activities increased for the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to a $985.3 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes including derivative cash settlements, decreased $101.8 million for the nine months ended September 30, 2017, compared with the same period in 2016, as a result of the decline in production volumes. Interest paid increased $36.3 million for the nine months ended September 30, 2017, compared with the same period in 2016, due to the issuance of our 2026 Notes and Senior Convertible Notes in the third quarter of 2016. These were partially offset by a $15.8$218.8 million decreaseincrease in cash paid on settled derivative trades and an increase in cash paid for LOE, including ad valorem taxtaxes, and G&A expense for the nine months ended September 30, 2017, compared with the same period in 2016. Further, netof $50.8 million. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements. During the third quarter of 2016, we paid $10.0 million to terminate a second lien facility that was not needed to fund the Rock Oil Acquisition.
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Investing activities
For the Nine Months Ended September 30,Amount Change Between Periods
20222021
(in millions)
Net cash used in investing activities$(592.4)$(544.8)$(47.6)
 For the Nine Months Ended 
 September 30,		 Amount Change Between Periods Percent Change Between Periods
 2017 2016  
 (in millions)  
Net cash provided by (used in) investing activities$69.0
 $(361.8) $430.8
 119%
Net cash used in investing activities increased for the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to increased capital expenditures of $41.6 million.

Financing activities
The increase
For the Nine Months Ended September 30,Amount Change Between Periods
20222021
(in millions)
Net cash used in financing activities$(639.9)$(155.6)$(484.3)
Net cash used in cash flow from investingfinancing activities for the nine months ended September 30, 2017, compared with2022, related to $480.2 million of cash paid, including premium, to redeem our 2025 Senior Secured Notes, and $104.8 million of cash paid to redeem our 2024 Senior Notes. These redemptions were made using cash on hand. Additionally, we paid $25.1 million for the same period in 2016 is largely duenet share settlement of employee and director stock awards and $20.2 million to increased divestiture cash proceeds of $576.5 million received. During the first nine months of 2017, these proceeds were primarily from the salerepurchase and subsequently retire 452,734 shares of our outside-operated Eagle Ford shale assets and duringcommon stock under the same period of 2016, the proceeds were primarily related to the divestiture of certain Permian and Rocky Mountain assets. Proceeds received from divestitures were partially offset by a $132.2 million increaseStock Repurchase Program.
Net cash used in capital expenditures, and a $65.5 million increase in proved and unproved property acquisitions in the Midland Basin during the first nine months of 2017 compared with the same period in 2016. Additionally, we made a $49.0 million deposit on the Rock Oil Acquisition during the third quarter of 2016.

Financingfinancing activities
 For the Nine Months Ended 
 September 30,		 Amount Change Between Periods Percent Change Between Periods
 2017 2016  
 (in millions)  
Net cash provided by (used in) financing activities$(7.6) $927.5
 $(935.1) (101)%

We had a zero balance on our credit facility as of December 31, 2016, and September 30, 2017, due to our significant cash balance resulting from the proceeds received from the sale of our Raven/Bear Den assets in December 2016 and proceeds received from the sale of our outside-operated Eagle Ford shale assets and other assets during the first nine months of 2017. This compares to net repayments of $202.0 million during for the nine months ended September 30, 2016. For2021, related to net repayments under our revolving credit facility of $93.0 million and $65.5 million of cash paid to retire our 2021 Senior Secured Convertible Notes. Additionally, we paid $385.3 million of net cash, including net premiums, to fund the nine months ended September 30, 2016,Tender Offer and the 2022 Senior Notes Redemption, and we received $530.9 million net proceeds from our underwritten public equity offering of approximately 18.4 million shares of our common stock at an offering price of $30.00 per share, $166.7 million net proceeds from our Senior Convertible Notes issuance, and $492.4 million net proceeds from our 2026 Notes issuance. We used a portion of the net cash proceeds of $392.8 million from these transactions to pay down our credit facility balance as of September 30, 2016 and used the remaining proceeds to partially fund the Rock Oil Acquisition that closed October 4, 2016. Please refer to Note 5 - Long-Term Debt and Note 15 - Equity in the Company’s 2016 Form 10-K for more information on the funding for these acquisitions. Additionally, during the nine months ended September 30, 2016, we paid $29.9 million for the repurchase of a portionissuance of our 2028 Senior Notes and we paid $24.1 million for capped call transactions related to our Senior Convertible Notes issuance. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.


Notes.
Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of September 30, 2017, and through the filing of this report, we had a zero balance on our credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes, or fixed-rate Senior Convertible Notes, but can impact their fair market values. As of September 30, 2017,2022, our outstanding principal amount of fixed-rate debt totaled $3.0 billion.$1.6 billion and we had no floating-rate debt outstanding. Please refer to Note 118 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes and Senior Convertible Notes.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, overall profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to wideunpredictable fluctuations in response toresulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment and other factors.weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last several years,decade, and remain subject to heightened levels of uncertainty and volatility related to (a) the ongoing conflict between Russia and Ukraine, (b) the economic and trade sanctions that certain countries have imposed on Russia, (c) production output from OPEC+, and the associated potential impacts of these markets will likely continueissues on global commodity and financial markets. These issues have contributed to be volatileinflation, supply chain disruptions, a rise in the future.interest rates, and could have further industry-specific impacts, which may require us to adjust our business plan. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our production for the nine months ended September 30, 2017,2022, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $45.1$180.0 million, $28.9$64.6 million, and $17.3$23.0 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2022, would have been higher, partially offsettingoffset the decreasedeclines in oil, gas, and NGL production revenues as discussed in the next paragraph.

revenue by approximately $128.2 million.
We enter into commodity derivative contracts in order to reduce the impactrisk of fluctuations in commodity prices. The fair value of our commodity derivative contracts areis largely determined by estimates of the forward curves of the relevant price indices. For the nine months endedAs of September 30, 2017,2022, a 10 percent increase or decrease in the contract settlement prices would have increasedforward curves associated with our oil, gas, and NGL commodity derivative settlement gaininstruments would have changed our net derivative positions for these products by approximately $24.2$79.2 million, $24.6$10.3 million, and $14.4$1.0 million, respectively.

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Off-Balance Sheet Arrangements

As part of our ongoing business, weWe have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions in 2017.

during the nine months ended September 30, 2022, or through the filing of this report.
Critical Accounting Policies and Estimates

Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 20162021 Form 10-K for discussion of our accounting policies and estimates.

Accounting Matters
New Accounting Pronouncements

Please refer to Note 21 - BasisSummary of Presentation, Significant Accounting Policies and Recently Issued Accounting Standards under in Part I, Item 1 of this report for information on new authoritative accounting pronouncements.guidance.

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Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, other non-operatinginterest income, and expense, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-timenon-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Credit AgreementNote 5 - Long-Term Debt in OverviewPart I, Item 1 of Liquidity and Capital Resources above.this report. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of senior securedtotal funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, and a minimum permitted ratio of adjusted EBITDAX to interest, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our sources of liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default.


The following table provides reconciliations of our net lossincome (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

For the Three Months Ended 
 September 30,		 For the Nine Months Ended 
 September 30,

2017 2016 2017 2016

(in thousands)
Net loss (GAAP)$(89,112) $(40,907) $(134,585) $(556,798)
Interest expense44,091
 47,206
 135,639
 112,329
Other non-operating income, net(1,301) (221) (2,901) (232)
Income tax benefit(39,270) (23,732) (65,825) (314,505)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion134,599
 193,966
 425,643
 619,193
Exploration (1)
12,748
 11,892
 35,395
 36,905
Impairment of proved properties—
 8,049
 3,806
 277,834
Abandonment and impairment of unproved properties—
 3,568
 157
 5,917
Stock-based compensation expense6,347
 6,570
 16,160
 20,485
Net derivative (gain) loss80,599
 (28,037) (89,364) 121,086
Derivative settlement gain13,092
 57,496
 29,402
 306,234
Net (gain) loss on divestiture activity1,895
 (22,388) 131,565
 (3,413)
(Gain) loss on extinguishment of debt—
 —
 35
 (15,722)
Other785
 (8,314) 5,620
 (4,757)
Adjusted EBITDAX (Non-GAAP)164,473

205,148
 490,747
 604,556
Interest expense(44,091)
(47,206) (135,639) (112,329)
Other non-operating income, net1,301

221
 2,901
 232
Income tax benefit39,270

23,732
 65,825
 314,505
Exploration (1)
(12,748)
(11,892) (35,395) (36,905)
Amortization of debt discount and deferred financing costs3,799
 3,757
 12,478
 5,687
Deferred income taxes(36,668) (23,756) (67,458) (314,770)
Plugging and abandonment(486) (2,506) (2,095) (5,222)
Other, net1,661
 (3,060) (920) (4,100)
Changes in current assets and liabilities11,971
 13,701
 40,153
 (36,642)
Net cash provided by operating activities (GAAP)$128,482

$158,139
 $370,597
 $415,012
For the Three Months Ended
September 30,		For the Nine Months Ended
September 30,
2022202120222021
(in thousands)
Net income (loss) (GAAP)$481,240 $85,593 $853,489 $(388,671)
Interest expense22,825 40,861 97,708 120,268 
Income tax expense (benefit)119,379 (39)218,951 (95)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion145,865 202,701 460,169 574,375 
Exploration (1)
13,203 7,801 41,152 23,742 
Impairment1,077 8,750 6,466 26,250 
Stock-based compensation expense5,105 4,498 13,858 14,191 
Net derivative (gain) loss(137,577)209,146 385,180 924,183 
Derivative settlement loss(186,299)(213,555)(595,080)(480,262)
(Gain) loss on extinguishment of debt— (5)67,605 2,139 
Other, net(4,663)905 (5,064)2,407 
Adjusted EBITDAX (non-GAAP)460,155 346,656 1,544,434 818,527 
Interest expense(22,825)(40,861)(97,708)(120,268)
Income tax (expense) benefit(119,379)39 (218,951)95 
Exploration (1)(2)
(11,993)

(7,801)(27,959)(23,742)
Amortization of debt discount and deferred financing costs1,303 3,905 8,910 13,350 
Deferred income taxes110,048 (68)202,996 (282)
Other, net(457)5,171 (461)(9,708)
Net change in working capital96,518 21,078 (13,230)52,170 
Net cash provided by operating activities (GAAP)$513,370 $328,119 $1,398,031 $730,142 

(1)    Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

Cautionary Information about Forward-Looking Statements

This report contains “forward-looking statements” within(2)    For the meaningthree and nine months ended September 30, 2022, amounts are net 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”). All statements, other than statements of historical facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:

the amount and nature of futurecertain capital expenditures and the availability of liquidity and capital resourcesrelated to fund capital expenditures;
our outlook on future oil, gas, and NGL prices, well costs, and service costs;
the drilling of wells and other exploration and development activities and plans, as well as possible or expected acquisitions or divestitures;
the possible divestiture or farm-down of, or joint venture relating to, certain properties;
proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates;
future oil, gas, and NGL production estimates;
cash flows, anticipated liquidity, and the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and
other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Some of these risks are described in the Risk Factors section in Part I, Item 1A of our 2016 Form 10-K, and include such factors as:
the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;
weakness in economic conditions and uncertainty in financial markets;
our ability to replace reserves in order to sustain production;
our ability to raise the substantial amount of capital required to develop and/or replace our reserves;
our ability to compete against competitors that have greater financial, technical, and human resources;
our ability to attract and retain key personnel;
the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;
the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;

the possibility that exploration and development drilling may not result in commercially producible reserves;
our limited control over activities on outside-operated properties;

our reliance on the skill and expertise of third-party service providers on our operated properties;

the possibility that title to properties in which we claim an interest may be defective;

our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;
the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;
the uncertainties associated with enhanced recovery methods;
our commodity derivative contracts may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;
the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
our ability to deliver required quantities of crude oil, natural gas, natural gas liquids, or water to contractual counterparties;
price declines or unsuccessful exploration efforts resulting in write-downsoutside of our asset carrying values;core areas of operations.
the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;
41
the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;
the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and Senior Convertible Notes may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions, or lead to the accelerated payment of our debt;

operating and environmental risks and hazards that could result in substantial losses;
the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities;
our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;
complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;
the availability and capacity of gathering, transportation, processing, and/or refining facilities;
our ability to sell and/or receive market prices for our oil, gas, and NGLs;
new technologies may cause our current exploration and drilling methods to become obsolete;
the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and

litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.

We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so, except as required by securities laws.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under the captions Interest Rate RiskandCommodity Price Risk in Item 2 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place in Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and is incorporated herein by reference. Please also refer to the information under Interest Rate RiskandCommodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 20162021 Form 10-K.10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that isare designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls wereare effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There werehave been no changes during the third quarter of 20172022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

42



PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time,At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are expectedlikely to have a materially adverse effect upon our financial condition, results of operations, or cash flows.

ITEM 1A. RISK FACTORS
Global geopolitical tensions, specifically including the ongoing conflict between Russia and Ukraine, may create heightened volatility in oil, gas, and NGL prices and could adversely affect our business, financial condition and results of operations.
On February 24, 2022, Russian military forces commenced a military operation in Ukraine and the sustained conflict and disruption in the region that has occurred since this date is expected to continue. Although the length, impact, and outcome of the ongoing military conflict in Ukraine is highly unpredictable, this conflict could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences, as well as increases in cyberattacks and espionage.
While it is not possible at this time to predict or determine the ultimate consequences of the conflict in Ukraine, which could include, among other things, additional sanctions, greater regional instability, embargoes, geopolitical shifts and other material and adverse effects on macroeconomic conditions, supply chains, financial markets, and hydrocarbon price volatility in particular is likely to continue for the foreseeable future. To the extent negotiations of a cease fire between Russia and Ukraine are unsuccessful, the potential destruction of critical oil-related infrastructure in Ukraine, and the implementation of further sanctions and other measures taken by governmental bodies and private actors, could have a lasting impact in the short- and long-term on the operations and financial condition of our business and the global economy.
There have been no other material changes to the risk factors as previously disclosed in our 20162021 Form 10-K.10-K.

43


ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table provides information about purchases made by us orand any “affiliated purchaser”affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the quarterthree months ended September 30, 2017,2022, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act:

PURCHASES OF EQUITY SECURITIES BY ISSUER
AND AFFILIATED PURCHASERS

Period
(a)



Total Number of Shares Purchased (1)
(b)



Weighted Average Price Paid per Share
(c)

Total Number of Shares Purchased as Part of Publicly Announced Program
(d)

Maximum Number of Shares that May Yet Be Purchased Under the Program (2)
07/01/17 - 07/31/1774,060
$16.53
—
3,072,184
08/01/17 - 08/31/17—
$—
—
3,072,184
09/01/17 - 09/30/17308
$14.49
—
3,072,184
Total:74,368
$16.52
—
3,072,184
PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES
Period
Total Number of Shares Purchased (1)
Weighted Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Program (2)
Maximum Number or Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program
(as of period end date) (2)(3)
07/01/2022 - 07/31/2022283,800 $34.19 — 3,072,184 
08/01/2022 - 08/31/2022— $— — 3,072,184 
09/01/2022 - 09/30/2022802,221 $44.42 452,734 $479,767,724 
Total:1,086,021 $41.75 452,734 

(1)
All shares purchased by us in the third quarter of 2017 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying restricted stock units delivered under the terms of grants under our Equity Incentive Compensation Plan.
(2)
In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to up to 6,000,000 shares as of the effective date of the resolution. Accordingly, as of the filing of this report, we may repurchase up to 3,072,184 shares of common stock on a prospective basis, subject to the approval of our Board of Directors. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time.

(1)    633,287 shares purchased by us in the third quarter of 2022 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs issued under the terms of award agreements granted under the Equity Plan.
(2)    On September 7, 2022, we announced that our Board of Directors approved the Stock Repurchase Program authorizing us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2024. The Stock Repurchase Program permits us to repurchase our shares from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of our Credit Agreement and the indentures governing our Senior Notes. We intend to fund repurchases from available working capital and cash provided by operating activities. Stock repurchases may also be funded with borrowings under our Credit Agreement. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased. During the three months ended September 30, 2022, we repurchased and subsequently retired 452,734 shares of our common stock under the Stock Repurchase Program at a weighted-average share price of $44.69 for a total cost of $20.2 million, excluding commissions and fees.
(3)    The Stock Repurchase Program terminates and supersedes the August 1998 authorization to repurchase common stock, under which 3,072,184 shares remained available for repurchase prior to termination.
Our payment of cash dividends to our stockholders is subject to certain covenants under the terms of our Credit Agreement that limit our annual dividend payments to no more than $50.0 million per year. We are also subject to certain covenants under the indentures governing our Senior Notes and Senior Convertible Notes that restrict certain payments, including dividends; provided, however, that the first $6.5 million of dividends paid each year are not restricted by these covenants. WeNotes. Based on our current performance, we do not anticipate that any of these restrictionscovenants will limit our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.

44


ITEM 6. EXHIBITS

The following exhibits are filed or furnished with, or incorporated by reference into this report:

Exhibit NumberDescription
Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)
12.1*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
101.INS*101.INSInline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*Inline XBRL Schema Document
101.CAL*Inline XBRL Calculation Linkbase Document
101.LAB*Inline XBRL Label Linkbase Document
101.PRE*Inline XBRL Presentation Linkbase Document
101.DEF*Inline XBRL Taxonomy Extension Definition Linkbase Document
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)

**Filed with this report.
****Furnished with this report.

45



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 hereuntothereunto duly authorized.

SM ENERGY COMPANY
November 3, 20174, 2022By:/s/ JAVAN D. OTTOSONHERBERT S. VOGEL
Javan D. OttosonHerbert S. Vogel
President and Chief Executive Officer
(Principal Executive Officer)
November 3, 20174, 2022By:/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
November 3, 20174, 2022By:/s/ MARK T. SOLOMONPATRICK A. LYTLE
Mark T. SolomonPatrick A. Lytle
Vice President - ControllerChief Accounting Officer and Assistant SecretaryController
(Principal Accounting Officer)


4946