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

For the quarterly period ended SeptemberJune 30, 20192020

OR

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

For the transition period from ___________ to ___________

Commission File Number 001-31539
sm-20200630_g1.jpg
SM ENERGY COMPANYCOMPANY
(Exact name of registrant as specified in its charter)
Delaware41-0518430
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
Delaware41-0518430
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 1200,Denver,Colorado80203
(Address of principal executive offices) (Zip(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 valueSMSMNew 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 ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☑Accelerated filer☐
Large accelerated filer☑Accelerated filer☐
Non-accelerated filer☐Smaller reporting company☐
Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
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 24, 2019,July 23, 2020, the registrant had 112,857,163114,458,893 shares of common stock outstanding.
1

TABLE OF CONTENTS

ItemPage
Cautionary Information about Forward-Looking Statements
3
ItemPage
Part I
34
Item 1.
Financial Statements (unaudited)
34
34
45
56
67
8
Notes to Condensed Consolidated Financial Statements
9
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
2627
Item 3.
4344
Item 4.
Controls and Procedures
4344
Part II
45
Item 1.
Legal Proceedings
45
Item 1A.
Risk Factors
45
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
4548
Item 6.
Exhibits
4649

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 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “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,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “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 impacts of macroeconomic events and the global COVID-19 pandemic (“Pandemic”) on us, our industry, our financial condition, results of operations, future operations, business prospects, capital and financial resources, ability to service our debt, ability to access the capital markets, and our plans to address the foregoing;
•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
•our expected total production volumes for the fiscal year 2020;
•any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (“Credit Agreement”);
•our outlook on future crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report) prices, well costs, service costs, lease operating costs, and general and administrative costs;
•our drilling of wells and other exploration and development activities, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;
•possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, 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;
•future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;
•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;
•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, and our outlook on our future financial condition or results of operations; 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 that we believe are appropriate under the circumstances. These statements are subject to 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. 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, 2019 (“2019 Form 10-K”), in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, our 2020 Proxy Statement, and the Risk Factors section in Part II, Item 1A of this report.
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 forward-looking statements. 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 data)
 September 30,
2019		 December 31,
2018
ASSETS   
Current assets:   
Cash and cash equivalents$10
 $77,965
Accounts receivable146,211
 167,536
Derivative assets143,142
 175,130
Prepaid expenses and other21,751
 8,632
Total current assets311,114
 429,263
Property and equipment (successful efforts method):   
Proved oil and gas properties8,143,381
 7,278,362
Accumulated depletion, depreciation, and amortization(3,953,181) (3,417,953)
Unproved oil and gas properties1,434,435
 1,581,401
Wells in progress325,230
 295,529
Properties held for sale, net—
 5,280
Other property and equipment, net of accumulated depreciation of $64,971 and $57,102, respectively79,278
 88,546
Total property and equipment, net6,029,143
 5,831,165
Noncurrent assets:   
Derivative assets38,571
 58,499
Other noncurrent assets74,255
 33,935
Total noncurrent assets112,826
 92,434
Total assets$6,453,083
 $6,352,862
LIABILITIES AND STOCKHOLDERS' EQUITY   
Current liabilities:   
Accounts payable and accrued expenses$431,440
 $403,199
Derivative liabilities37,798
 62,853
Other current liabilities21,804
 —
Total current liabilities491,042
 466,052
Noncurrent liabilities:   
Revolving credit facility129,000
 —
Senior Notes, net of unamortized deferred financing costs2,451,886
 2,448,439
Senior Convertible Notes, net of unamortized discount and deferred financing costs154,883
 147,894
Asset retirement obligations95,806
 91,859
Deferred income taxes217,469
 223,278
Derivative liabilities6,014
 12,496
Other noncurrent liabilities63,233
 42,522
Total noncurrent liabilities3,118,291
 2,966,488
    
Commitments and contingencies (note 6)


 


    
Stockholders’ equity:   
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,857,163 and 112,241,966 shares, respectively1,129
 1,122
Additional paid-in capital1,784,787
 1,765,738
Retained earnings1,069,642
 1,165,842
Accumulated other comprehensive loss(11,808) (12,380)
Total stockholders’ equity2,843,750
 2,920,322
Total liabilities and stockholders’ equity$6,453,083
 $6,352,862

June 30,
2020		December 31,
2019
ASSETS
Current assets:
Cash and cash equivalents$10  $10  
Accounts receivable127,173  184,732  
Derivative assets211,582  55,184  
Prepaid expenses and other16,704  12,708  
Total current assets355,469  252,634  
Property and equipment (successful efforts method):
Proved oil and gas properties8,134,461  8,934,020  
Accumulated depletion, depreciation, and amortization(4,536,537) (4,177,876) 
Unproved oil and gas properties923,666  1,005,887  
Wells in progress266,957  118,769  
Other property and equipment, net of accumulated depreciation of $65,447 and $64,032, respectively37,278  72,848  
Total property and equipment, net4,825,825  5,953,648  
Noncurrent assets:
Derivative assets34,390  20,624  
Other noncurrent assets51,944  65,326  
Total noncurrent assets86,334  85,950  
Total assets$5,267,628  $6,292,232  
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses$257,053  $402,008  
Derivative liabilities38,250  50,846  
Other current liabilities12,597  19,189  
Total current liabilities307,900  472,043  
Noncurrent liabilities:
Revolving credit facility193,000  122,500  
Senior Notes, net2,263,119  2,610,298  
Asset retirement obligations86,628  84,134  
Deferred income taxes57,049  189,386  
Derivative liabilities24,028  3,444  
Other noncurrent liabilities55,072  61,433  
Total noncurrent liabilities2,678,896  3,071,195  
Commitments and contingencies (note 6)
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 113,553,271 and 112,987,952 shares, respectively1,136  1,130  
Additional paid-in capital1,825,327  1,791,596  
Retained earnings465,310  967,587  
Accumulated other comprehensive loss(10,941) (11,319) 
Total stockholders’ equity2,280,832  2,748,994  
Total liabilities and stockholders’ equity$5,267,628  $6,292,232  
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 data)
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
Operating revenues and other income:
Oil, gas, and NGL production revenue$169,790  $406,854  $524,023  $747,330  
Net gain on divestiture activity91  262  91  323  
Other operating revenues(249) 56  1,252  449  
Total operating revenues and other income169,632  407,172  525,366  748,102  
Operating expenses:
Oil, gas, and NGL production expense80,445  123,050  199,997  244,355  
Depletion, depreciation, amortization, and asset retirement obligation liability accretion180,856  206,330  414,345  384,076  
Exploration9,787  10,877  21,136  22,225  
Impairment8,750  12,417  998,513  18,755  
General and administrative27,227  30,920  54,674  63,006  
Net derivative (gain) loss167,200  (79,655) (378,140) 97,426  
Other operating (income) expense, net8,046  (934) 8,612  (599) 
Total operating expenses482,311  303,005  1,319,137  829,244  
Income (loss) from operations(312,679) 104,167  (793,771) (81,142) 
Interest expense(40,354) (39,627) (81,866) (77,607) 
Gain on extinguishment of debt227,281  —  239,476  —  
Other non-operating expense, net(185) (562) (679) (879) 
Income (loss) before income taxes(125,937) 63,978  (636,840) (159,628) 
Income tax (expense) benefit36,685  (13,590) 135,693  32,448  
Net income (loss)$(89,252) $50,388  $(501,147) $(127,180) 
Basic weighted-average common shares outstanding113,008  112,262  113,015  112,257  
Diluted weighted-average common shares outstanding113,008  112,932  113,015  112,257  
Basic net income (loss) per common share$(0.79) $0.45  $(4.43) $(1.13) 
Diluted net income (loss) per common share$(0.79) $0.45  $(4.43) $(1.13) 
Dividends per common share$—  $—  $0.01  $0.05  
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
Operating revenues and other income:       
Oil, gas, and NGL production revenue$389,419
 $458,382
 $1,136,749
 $1,243,826
Net gain on divestiture activity—
 786
 323
 425,656
Other operating revenues898
 201
 1,347
 3,398
Total operating revenues and other income390,317

459,369

1,138,419

1,672,880
Operating expenses:










Oil, gas, and NGL production expense129,042
 127,638
 373,397
 365,917
Depletion, depreciation, amortization, and asset retirement obligation liability accretion211,125
 201,105
 595,201
 483,343
Exploration11,626
 13,061
 33,851
 40,844
Abandonment and impairment of unproved properties6,337
 9,055
 25,092
 26,615
General and administrative32,578
 29,464
 95,584
 86,066
Net derivative (gain) loss(100,889) 178,026
 (3,463) 249,304
Other operating expenses, net1,021
 9,664
 422
 14,219
Total operating expenses290,840

568,013

1,120,084

1,266,308
Income (loss) from operations99,477

(108,644)
18,335

406,572
Interest expense(40,584) (38,111) (118,191) (122,850)
Loss on extinguishment of debt—
 (26,722) —
 (26,722)
Other non-operating income (expense), net(548) 806
 (1,427) 3,017
Income (loss) before income taxes58,345

(172,671)
(101,283)
260,017
Income tax (expense) benefit(16,111) 36,748
 16,337
 (61,342)
Net income (loss)$42,234
 $(135,923) $(84,946)
$198,675
 










Basic weighted-average common shares outstanding112,804
 112,107
 112,441
 111,836
Diluted weighted-average common shares outstanding113,334
 112,107
 112,441
 113,600
Basic net income (loss) per common share$0.37
 $(1.21) $(0.76) $1.78
Diluted net income (loss) per common share$0.37
 $(1.21) $(0.76) $1.75
Dividends per common share$0.05
 $0.05
 $0.10
 $0.10

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
June 30,		For the Six Months Ended
June 30,
2020201920202019
Net income (loss)$(89,252) $50,388  $(501,147) $(127,180) 
Other comprehensive income, net of tax:
Pension liability adjustment188  119  378  382  
Total other comprehensive income, net of tax188  119  378  382  
Total comprehensive income (loss)$(89,064) $50,507  $(500,769) $(126,798) 
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
Net income (loss)$42,234
 $(135,923) $(84,946) $198,675
Other comprehensive income, net of tax:       
Pension liability adjustment190
 263
 572
 721
Total other comprehensive income, net of tax190
 263
 572
 721
Total comprehensive income (loss)$42,424
 $(135,660) $(84,374) $199,396

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, 2019112,987,952  $1,130  $1,791,596  $967,587  $(11,319) $2,748,994  
Net loss—  —  —  (411,895) —  (411,895) 
Other comprehensive income—  —  —  —  190  190  
Cash dividends declared, $0.01 per share—  —  —  (1,130) —  (1,130) 
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings730  —  (3) —  —  (3) 
Stock-based compensation expense—  —  5,561  —  —  5,561  
Balances, March 31, 2020112,988,682  $1,130  $1,797,154  $554,562  $(11,129) $2,341,717  
Net loss—  —  —  (89,252) —  (89,252) 
Other comprehensive income—  —  —  —  188  188  
Issuance of common stock under Employee Stock Purchase Plan297,013  3  944  —  —  947  
Stock-based compensation expense267,576  3  5,709  —  —  5,712  
Issuance of warrants—  —  21,520  —  —  21,520  
Balances, June 30, 2020113,553,271  $1,136  $1,825,327  $465,310  $(10,941) $2,280,832  
Additional Paid-in CapitalAccumulated Other Comprehensive LossTotal Stockholders’ Equity
Common StockRetained Earnings
SharesAmount
Balances, December 31, 2018112,241,966  $1,122  $1,765,738  $1,165,842  $(12,380) $2,920,322  
Net loss—  —  —  (177,568) —  (177,568) 
Other comprehensive income—  —  —  —  263  263  
Cash dividends declared, $0.05 per share—  —  —  (5,612) —  (5,612) 
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings2,579  —  (18) —  —  (18) 
Stock-based compensation expense—  —  5,838  —  —  5,838  
Balances, March 31, 2019112,244,545  $1,122  $1,771,558  $982,662  $(12,117) $2,743,225  
Net income—  —  —  50,388  —  50,388  
Other comprehensive income—  —  —  —  119  119  
Issuance of common stock under Employee Stock Purchase Plan184,079  2  1,957  —  —  1,959  
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings290  —  (2) —  —  (2) 
Stock-based compensation expense96,719  1  6,153  —  —  6,154  
Other—  —  (1) 1  —  —  
Balances, June 30, 2019112,525,633  $1,125  $1,779,665  $1,033,051  $(11,998) $2,801,843  
   Additional Paid-in Capital   Accumulated Other Comprehensive Loss Total Stockholders’ Equity
 Common Stock  Retained Earnings  
 Shares Amount    
Balances, December 31, 2018112,241,966
 $1,122
 $1,765,738
 $1,165,842
 $(12,380) $2,920,322
Net loss—
 —
 —
 (177,568) —
 (177,568)
Other comprehensive income—
 —
 —
 —
 263
 263
Cash dividends declared, $0.05 per share—
 —
 —
 (5,612) —
 (5,612)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings2,579
 —
 (18) —
 —
 (18)
Stock-based compensation expense—
 —
 5,838
 —
 —
 5,838
Balances, March 31, 2019112,244,545
 $1,122
 $1,771,558
 $982,662
 $(12,117) $2,743,225
Net income—
 —
 —
 50,388
 —
 50,388
Other comprehensive income—
 —
 —
 —
 119
 119
Issuance of common stock under Employee Stock Purchase Plan184,079
 2
 1,957
 —
 —
 1,959
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings290
 —
 (2) —
 —
 (2)
Stock-based compensation expense96,719
 1
 6,153
 —
 —
 6,154
Other—
 —
 (1) 1
 —
 —
Balances, June 30, 2019112,525,633
 $1,125
 $1,779,665
 $1,033,051
 $(11,998) $2,801,843
Net income—
 —
 —
 42,234
 —
 42,234
Other comprehensive income—
 —
 —
 —
 190
 190
Cash dividends declared, $0.05 per share—
 —
 —
 (5,643) —
 (5,643)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings331,530
 4
 (1,644) —
 —
 (1,640)
Stock-based compensation expense—
 —
 6,766
 —
 —
 6,766
Balances, September 30, 2019112,857,163
 $1,129
 $1,784,787
 $1,069,642
 $(11,808) $2,843,750

The accompanying notes are an integral part of these condensed consolidated financial statements.
7

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITYCASH FLOWS (UNAUDITED) (Continued)
(in thousands, except share datathousands)
For the Six Months Ended June 30,
20202019
Cash flows from operating activities:
Net loss$(501,147) $(127,180) 
Adjustments to reconcile net loss to net cash provided by operating activities
Net gain on divestiture activity(91) (323) 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion414,345  384,076  
Impairment998,513  18,755  
Stock-based compensation expense11,273  11,992  
Net derivative (gain) loss(378,140) 97,426  
Derivative settlement gain (loss)215,965  (879) 
Amortization of debt discount and deferred financing costs8,578  7,633  
Gain on extinguishment of debt(239,476) —  
Deferred income taxes(136,268) (33,237) 
Other, net(3,827) (1,287) 
Net change in working capital(57,254) 21,454  
Net cash provided by operating activities332,471  378,430  
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties (1)
92  12,520  
Capital expenditures(310,209) (576,127) 
Other, net—  319  
Net cash used in investing activities(310,117) (563,288) 
Cash flows from financing activities:
Proceeds from revolving credit facility841,000  696,500  
Repayment of revolving credit facility(770,500) (578,500) 
Debt issuance costs related to 10.0% Senior Secured Notes due 2025(10,491) —  
Cash paid to repurchase 6.125% Senior Notes due 2022(28,318) —  
Repayment of 1.50% Senior Convertible Notes due 2021(53,508) —  
Net proceeds from sale of common stock947  1,959  
Dividends paid(1,130) (5,612) 
Other, net(354) (1,044) 
Net cash provided by (used in) financing activities(22,354) 113,303  
Net change in cash, cash equivalents, and restricted cash—  (71,555) 
Cash, cash equivalents, and restricted cash at beginning of period10  77,965  
Cash, cash equivalents, and restricted cash at end of period$10  $6,410  
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest$(82,313) $(67,646) 
Investing activities:
Decrease in capital expenditure accruals and other$(28,896) $(10,097) 
Supplemental non-cash investing activities:
Carrying value of properties exchanged$—  $66,588  
Supplemental non-cash financing activities:
Non-cash gain on extinguishment of debt, net$292,984  $—  
Reconciliation of cash, cash equivalents, and restricted cash:
Cash and cash equivalents$10  $12  
Restricted cash (1)
—  6,398  
Cash, cash equivalents, and restricted cash at end of period$10  $6,410  

(1) As of June 30, 2019, a portion of net proceeds from the sale of oil and dividends per share)

   Additional Paid-in Capital   Accumulated Other Comprehensive Loss Total Stockholders’ Equity
 Common Stock  Retained Earnings  
 Shares Amount    
Balances, December 31, 2017111,687,016
 $1,117
 $1,741,623
 $665,657
 $(13,789) $2,394,608
Net income—
 —
 —
 317,401
 —
 317,401
Other comprehensive income—
 —
 —
 —
 260
 260
Cash dividends declared, $0.05 per share—
 —
 —
 (5,584) —
 (5,584)
Stock-based compensation expense—
 —
 5,412
 —
 —
 5,412
Cumulative effect of accounting change—
 —
 —
 2,969
 (2,969) —
Other—
 —
 —
 1
 (1) —
Balances, March 31, 2018111,687,016
 $1,117
 $1,747,035
 $980,444
 $(16,499) $2,712,097
Net income—
 —
 —
 17,197
 —
 17,197
Other comprehensive income—
 —
 —
 —
 198
 198
Issuance of common stock under Employee Stock Purchase Plan100,249
 1
 1,880
 —
 —
 1,881
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings1,161
 —
 (10) —
 —
 (10)
Stock-based compensation expense58,572
 —
 5,264
 —
 —
 5,264
Balances, June 30, 2018111,846,998
 $1,118
 $1,754,169
 $997,641
 $(16,301) $2,736,627
Net loss—
 —
 —
 (135,923) —
 (135,923)
Other comprehensive income—
 —
 —
 —
 263
 263
Cash dividends declared, $0.05 per share—
 —
 —
 (5,607) —
 (5,607)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings290,584
 3
 (2,968) —
 —
 (2,965)
Stock-based compensation expense—
 —
 7,004
 —
 —
 7,004
Balances, September 30, 2018112,137,582
 $1,121
 $1,758,205
 $856,111
 $(16,038) $2,599,399
gas properties was restricted for future property acquisitions. Restricted cash is included in the other noncurrent assets line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”).
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,
 2019 2018
Cash flows from operating activities:   
Net income (loss)$(84,946) $198,675
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Net gain on divestiture activity(323) (425,656)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion595,201
 483,343
Abandonment and impairment of unproved properties25,092
 26,615
Stock-based compensation expense18,758
 17,680
Net derivative (gain) loss(3,463) 249,304
Derivative settlement gain (loss)23,843
 (101,911)
Amortization of debt discount and deferred financing costs11,554
 11,542
Loss on extinguishment of debt—
 26,722
Deferred income taxes(13,620) 60,672
Other, net(2,291) (2,084)
Net change in working capital11,781
 (3,725)
Net cash provided by operating activities581,586
 541,177
Cash flows from investing activities:   
Net proceeds from the sale of oil and gas properties (1)
12,520
 743,199
Capital expenditures(788,642) (1,032,588)
Acquisition of proved and unproved oil and gas properties(2,581) (24,571)
Net cash used in investing activities(778,703) (313,960)
Cash flows from financing activities:   
Proceeds from credit facility1,124,500
 —
Repayment of credit facility(995,500) —
Net proceeds from Senior Notes—
 492,079
Cash paid to repurchase Senior Notes, including premium—
 (844,984)
Net proceeds from sale of common stock1,959
 1,881
Dividends paid(5,612) (5,584)
Other, net(2,684) (7,746)
Net cash provided by (used in) financing activities122,663
 (364,354)
Net change in cash, cash equivalents, and restricted cash(74,454) (137,137)
Cash, cash equivalents, and restricted cash at beginning of period77,965
 313,943
Cash, cash equivalents, and restricted cash at end of period$3,511
 $176,806
    
Supplemental schedule of additional cash flow information and non-cash activities:   
Operating activities:   
Cash paid for interest, net of capitalized interest$(113,122) $(124,435)
Net cash paid for income taxes$(1,469) $(9,085)
Investing activities:   
Changes in capital expenditure accruals and other$34,878
 $19,811
Supplemental non-cash investing activities:   
Carrying value of properties exchanged$70,808
 $95,121
Supplemental non-cash financing activities:   
Non-cash loss on extinguishment of debt, net$—
 $6,334
    
Reconciliation of cash, cash equivalents, and restricted cash:   
Cash and cash equivalents$10
 $176,806
Restricted cash (1)
3,501
 —
Cash, cash equivalents, and restricted cash at end of period$3,511
 $176,806

(1)
As of September 30, 2019, a portion of net proceeds from the sale of oil and gas properties was restricted for future property acquisitions. Restricted cash is included in the other noncurrent assets line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”).
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 - Summary 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.the State of Texas.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of the 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 the Company’s Annual Report on2019 Form 10-K for the year ended December 31, 2018 (the “2018 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 SeptemberJune 30, 2019,2020, and through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in 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 in the 20182019 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 20182019 Form 10-K.10-K.
Recently Issued Accounting Standards
In February 2016,December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases2019-12, Income Taxes (Topic 842), followed by other740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). ASU 2019-12 was issued to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting standard. The guidance is to be applied using a prospective method, excluding amendments related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02”to franchise taxes, which should be applied on either a retrospective basis for all periods presented or “Topic 842”).a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company early adopted ASU 2016-022019-12 on January 1, 2019, using2020, and there was no material impact on the modified retrospective method.Company’s unaudited condensed consolidated financial statements or disclosures upon adoption.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 is effective for all entities as of March 12, 2020 through December 31, 2022. The Company elected as part of its adoption to also useis evaluating the optional transition methodology whereby lease accounting for previously reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and practical expedients the Company has implemented in connection with the adoption ofoptions provided by ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources.
Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this guidance.2020-04. Please refer to Note 125 - LeasesLong-Term Debt for additional discussion.discussion of the use of the London Interbank Offered Rate (“LIBOR”) in connection with borrowings under the Credit Agreement.
Other than asAs disclosed in the 20182019 Form 10-K, on January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, and ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. As expected, there was no material impact on the Company’s unaudited condensed consolidated financial statements or disclosures upon adoption of these ASUs.
There are no ASUs 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 SeptemberJune 30, 2019, and2020, or through the filing of this report.
9

Note 2 - Revenue from Contracts with Customers
The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs from its Midland Basin and South Texas assets. Following the divestiture of the Company’s remaining assets in the Rocky Mountain region during the first half of 2018, there has been no production revenue from this region after the second quarter of 2018. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) is reflective of the revenue generated from contracts with customers.

The tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three and ninesix months ended SeptemberJune 30, 2019,2020, and 2018:2019:
Midland Basin South Texas TotalMidland BasinSouth TexasTotal
Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30,Three Months Ended
June 30,		Three Months Ended
June 30,		Three Months Ended
June 30,
2019 2018 2019 2018 2019 2018202020192020201920202019
(in thousands)(in thousands)
Oil production revenue$277,361
 $270,086
 $15,496
 $17,436
 $292,857
 $287,522
Oil production revenue$114,358  $288,447  $5,158  $15,697  $119,516  $304,144  
Gas production revenue17,780
 40,364
 46,267
 56,446
 64,047
 96,810
Gas production revenue11,921  16,449  22,942  48,775  34,863  65,224  
NGL production revenue124
 563
 32,391
 73,487
 32,515
 74,050
NGL production revenue45  (43) 15,366  37,529  15,411  37,486  
Total$295,265
 $311,013
 $94,154
 $147,369
 $389,419
 $458,382
Total$126,324  $304,853  $43,466  $102,001  $169,790  $406,854  
Relative percentage76% 68% 24% 32% 100% 100%Relative percentage74 %75 %26 %25 %100 %100 %

Note: Amounts may not calculate due to rounding.
 Midland Basin South Texas Rocky Mountain Total
 Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018 2019 2018 2019 2018
 (in thousands)
Oil production revenue$791,055
 $703,516
 $45,007
 $56,365
 $—
 $54,851
 $836,062
 $814,732
Gas production revenue49,821
 96,974
 144,563
 161,414
 —
 1,595
 194,384
 259,983
NGL production revenue102
 816
 106,201
 167,505
 —
 790
 106,303
 169,111
Total$840,978
 $801,306
 $295,771
 $385,284
 $—
 $57,236
 $1,136,749
 $1,243,826
Relative percentage74% 64% 26% 31% —% 5% 100% 100%

Midland BasinSouth TexasTotal
Six Months Ended
June 30,		Six Months Ended
June 30,		Six Months Ended
June 30,
202020192020201920202019
(in thousands)
Oil production revenue$390,494  $513,694  $20,715  $29,511  $411,209  $543,205  
Gas production revenue23,255  32,041  52,318  98,296  75,573  130,337  
NGL production revenue103  (22) 37,138  73,810  37,241  73,788  
Total$413,852  $545,713  $110,171  $201,617  $524,023  $747,330  
Relative percentage79 %73 %21 %27 %100 %100 %

Note: Amounts may not calculate due to rounding.
The Company recognizes oil, gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differdiffers depending on the applicable contractual terms. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of 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, whileoperations. 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 controlthe transfer are embedded in the price and effectively recorded as a reduction of oil, gas, and NGL production revenue.control. Please refer to Note 2 - Revenue from Contracts with Customers in the 20182019 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 (“ASC”) 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; thus, there are 0 material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
10

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 production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of SeptemberJune 30, 2019,2020, and December 31, 2018,2019, were $106.3$60.9 million and $107.2$146.3 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. Revenue recognized that related to performance obligations satisfied in prior reporting periods was immaterial for the three and nine months ended September 30, 2019, and 2018.
Note 3 - Divestitures, Assets Held for Sale, and Acquisitions
Divestitures
No material divestitures occurred during the first ninesix months of 2020 and 2019, and there were 0 assets classified as held for sale as of SeptemberJune 30, 2019.
On March 26, 2018,the Company divested approximately 112,000 net acres of its Powder River Basin assets (the “PRB Divestiture”) for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $490.8 million, subject to final purchase price adjustments, and recorded an estimated net gain of $410.6 million for the nine months ended September 30, 2018. After final purchase price adjustments, the Company received net divestiture proceeds of $492.2 million, and recorded a final net gain of $410.6 million related to these divested assets for the year ended2020, or December 31, 2018.
During the second quarter of 2018, the Company completed the divestitures of its remaining Williston Basin assets located in Divide County, North Dakota (the “Divide County Divestiture”) and its Halff East assets in the Midland Basin (the “Halff East Divestiture”), for combined net divestiture proceeds of $250.8 million, subject to final purchase price adjustments, and recorded a combined estimated net gain of $15.4 million for the nine months ended September 30, 2018. After final purchase price adjustments, the Company received net divestiture proceeds of $252.2 million, and recorded a final net gain of $15.4 million related to these divested assets for the year ended December 31, 2018.2019.
Acquisitions
No material acquisitions or acreage trades of oil and gas properties occurred during the first half of 2020. During the first nine monthshalf of 2019, the Company completed several non-monetary acreage trades of primarily undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the exchange of approximately 2,1002,000 net acres, with $70.8 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with 0 gain or loss recognized. During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily undeveloped properties located in Howard and Martin Counties, Texas, which resulted in the exchange of approximately 2,650 net acres, with $95.1$66.6 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with 0 gain or loss recognized.
During the second quarter of 2018, the Company acquired approximately 720 net acres of unproved properties in Martin County, Texas, for $24.6 million. Under authoritative accounting guidance, this transaction was considered an asset acquisition. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired.
Note 4 - Income Taxes
The provision for income taxes for the three and six months ended June 30, 2020, and 2019, consisted of the following:
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in thousands)
Current portion of income tax (expense) benefit:
Federal$—  $—  $—  $—  
State(236) 176  (575) (789) 
Deferred portion of income tax (expense) benefit36,921  (13,766) 136,268  33,237  
Income tax (expense) benefit$36,685  $(13,590) $135,693  $32,448  
Effective tax rate29.1 %21.2 %21.3 %20.3 %
Recorded income tax expense or benefit differs from the amounts that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax limitations on the compensation of certain covered individuals, changes in valuation allowances, and the cumulative impact of other smaller permanent differences. The quarterly rate can also be affected by the proportional impacts of forecasted net income or loss for each period presented, as reflected in the table below.above.
The provision for income taxes for the three and nine months ended September 30, 2019, and 2018, consisted of the following:
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in thousands)
Current portion of income tax (expense) benefit:       
Federal$3,826
 $—
 $3,826
 $—
State(320) (85) (1,109) (670)
Deferred portion of income tax (expense) benefit(19,617) 36,833
 13,620
 (60,672)
Income tax (expense) benefit$(16,111) $36,748
 $16,337
 $(61,342)
Effective tax rate27.6% 21.3% 16.1% 23.6%


TheA change in the Company’s effective tax rate between reporting periods will generally reflect differences in estimating permanent differences compared to changes in forecasted net income or loss. Each quarter, the Company evaluates its deferred tax assets for potential realization, weighing both positive and negative evidence to determine, on a more likely than not basis, the future utilization by asset and jurisdiction. When the significance of negative evidence outweighs the Company’s positive support of realization, a valuation allowance is recorded. Subsequently, when the significance of positive evidence outweighs negative evidence that a deferred tax asset will be realized, the valuation allowance is released.
During the second quarter of 2020, the Company executed certain debt exchange transactions that resulted in cancellation of debt income and supported the utilization of its deferred tax assets. As a result, the Company released the valuation allowance recorded in the previous quarter which increased the Company’s income tax benefit and tax benefit rate for the three months ended SeptemberJune 30, 2019, compared with the same period in 2018, was primarily due to the differing effects of permanent items on income before income taxes for the three months ended September 30, 2019, compared to their impact on the loss before income taxes for the same period in 2018.

2020.
The change inCoronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The primary feature of the effective tax rate forCARES Act that the nine months ended September 30, 2019, compared withCompany benefited from was the same period in 2018, was primarily due to the differing effectsacceleration of permanent items on the loss before income taxes for the nine months ended September 30, 2019, compared to their impact on income before income taxes for the same period in 2018.  Additionally, the year-to-date 2018 rate was also impacted by the estimated highest marginal state tax rates due to changes in the composition of income or loss from Company activities, including divestitures, among multiple state tax jurisdictions.  Future periods are not expected to reflect these differences as the Company’s current activities are occurring predominately in Texas.
Subsequent to September 30, 2019,its refundable Alternative Minimum Tax (“AMT”) credits. On April 1, 2020, the Company filed an election to accelerate its 2018 federal income tax return claiming a $7.7 millionremaining refundable AMT credits of $7.6 million. The Company received the refund for a portion of its deferred AMT credit carryover. in July 2020.
11

For all years before 2015, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.
Note 5 - Long-Term Debt
Credit Agreement
On September 19, 2019,During the second quarter of 2020, the Company initiated an offer to exchange its outstanding senior unsecured notes, as presented in the Senior Unsecured Notes section below (“Senior Unsecured Notes”), other than the 1.50% Senior Convertible Notes due 2021 (“2021 Senior Convertible Notes,” and together with the Senior Unsecured Notes, “Old Notes”), and a private exchange of its outstanding 2021 Senior Convertible Notes and portions of its outstanding Senior Unsecured Notes (“Private Exchange”), in each case for newly issued 10.0% Senior Secured Second Lien Notes due January 15, 2025 (“2025 Senior Secured Notes”), referred to together as “Exchange Offers.” In connection with the Exchange Offers, the Company and its lenders enteredamended the Credit Agreement to increase the amount of permitted second lien indebtedness to an aggregate amount of $1.0 billion, inclusive of the 2021 Senior Convertible Notes (“Permitted Second Lien Debt”). Additionally, the Company amended the indenture governing its 2021 Senior Convertible Notes, by entering into the Second AmendmentThird Supplemental Indenture, dated as of April 29, 2020, (“Third Supplemental Indenture”), to the Sixth Amendedoriginal Indenture, dated as of May 21, 2015, as supplemented and Restatedamended by the Second Supplemental Indenture, dated as of August 12, 2016, collectively referred to as the “2021 Notes Indenture.” The Third Supplemental Indenture provides that the Company will satisfy any conversion obligation solely in cash.
On June 17, 2020 (“Settlement Date”), the Company exchanged $611.9 million in aggregate principal amount of Senior Unsecured Notes and $107.0 million in aggregate principal amount of 2021 Senior Convertible Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes, as well as, in connection with the Private Exchange, (a) $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes and (b) warrants to acquire up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, exercisable upon the occurrence of certain future triggering events, to certain holders who exchanged Old Notes in the Private Exchange. Please refer to Note 11 - Fair Value Measurements for more information regarding the warrants issued by the Company. Pursuant to the 2021 Notes Indenture, upon the issuance of Permitted Second Lien Debt, the remaining outstanding 2021 Senior Convertible Notes became secured and are subsequently referred to as the “2021 Senior Secured Convertible Notes,” and together with the 2025 Senior Secured Notes, the “Senior Secured Notes.”
The following table summarizes the principal amounts of the Old Notes tendered as of the Settlement Date:
Title of Old Notes TenderedPrincipal Amount of Old Notes Tendered
(in thousands)
1.50% Senior Convertible Notes due 2021$107,015 
6.125% Senior Notes due 2022141,701
5.0% Senior Notes due 2024155,339
5.625% Senior Notes due 2025150,882
6.75% Senior Notes due 202680,765
6.625% Senior Notes due 202783,209
Total$718,911 
Please refer to the Credit Agreement, Senior Secured Notes, and Senior Unsecured Notes sections below for additional information regarding the debt transactions conducted by the Company during the second quarter of 2020.
Credit Agreement
The Company’s Credit Agreement which permitted the Company to enter into swap agreements with respect to the price of electricity in order to minimize exposure to electrical price volatility. As of September 30, 2019, the Company’s Sixth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), providedprovides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, a borrowing basebillion. During the second quarter of $1.6 billion, and aggregate lender commitments of $1.2 billion. Subsequent to September 30, 2019,2020, the Company and its lenders completed the semi-annual borrowing base redetermination, which reaffirmedand entered into the Third Amendment and the Fourth Amendment to the Credit Agreement (collectively, “Amendments”). As a result of lower commodity prices and a corresponding decrease in the value of the Company’s proved reserves, the borrowing base and aggregate lender commitments at existing levels.were both reduced to $1.1 billion. The Amendments permitted the Company to incur second lien debt of up to $827.5 million prior to the next scheduled borrowing base redetermination date is Aprilof October 1, 2020.2020, provided that all principal amounts of such debt are used to redeem unsecured senior debt of the Company for less than or equal to 80% of par value. The Amendments also permitted the Company to grant a second-priority security interest to the holders of the Company’s outstanding 2021 Senior Convertible Notes to secure the Company’s obligations under the 2021 Senior Convertible Notes. As a result, the Company may incur Permitted Second Lien Debt in an aggregate amount of up to $1.0 billion. As of June 30, 2020, the Company had $487.8 million of available Permitted Second Lien Debt capacity. Additionally, the Amendments reduced the amount of dividends that the Company may declare and pay on an annual basis from $50.0 million to $12.0 million.
The Credit Agreement is scheduled to mature on September 28, 2023. The2023, except that, pursuant to the Amendments, newly issued Permitted Second Lien Debt used to redeem any portion of the remaining 6.125% Senior Notes due 2022 (“2022 Senior Notes”) must have maturities on or after 180 days after September 28, 2023; otherwise, the maturity date of the Credit Agreement will be July 2, 2023. Without regard to which maturity date is in effect, the maturity date could however, occur earlier on August 16, 2022, if the Company has
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not completed certain repurchase, redemption, or refinancing activities associated with its 6.125%2022 Senior Notes, due 2022 (“2022 Senior Notes”),and does not have certain unused availability for borrowing under the Credit Agreement, as outlined in the Credit Agreement. The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement and was in compliance with all such covenants as of September 30, 2019, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in the 2018 Form 10-K for additional detail on the terms of the Company’s Credit Agreement.
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. The Third Amendment to the Credit Agreement amended the borrowing base utilization grid as presented in Note 5 - Long-Term Debt in the Company’s 2018 Form 10-K.table below. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at the London Interbank Offered Rate,LIBOR, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations.
Borrowing Base Utilization Percentage<25%≥25% <50%≥50% <75%≥75% <90%≥90%
Eurodollar Loans (1)
1.750 %2.000 %2.500 %2.750 %3.000 %
ABR Loans or Swingline Loans0.750 %1.000 %1.500 %1.750 %2.000 %
Commitment Fee Rate0.375 %0.375 %0.500 %0.500 %0.500 %

(1) The Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the Company. Please refer to Note 1 - Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04, which provides guidance related to reference rate reform.
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 24, 2019, SeptemberJuly 23, 2020, June 30, 2019,2020, and December 31, 2018:2019:
As of October 24, 2019 As of September 30, 2019 As of December 31, 2018As of July 23, 2020As of June 30, 2020As of December 31, 2019
(in thousands)(in thousands)
Revolving credit facility (1)
$143,000
 $129,000
 $—
Revolving credit facility (1)
$180,000  $193,000  $122,500  
Letters of credit (2)
—
 —
 200
Letters of credit (2)
42,000  42,000  —  
Available borrowing capacity1,057,000
 1,071,000
 999,800
Available borrowing capacity878,000  865,000  1,077,500  
Total aggregate lender commitment amount$1,200,000
 $1,200,000
 $1,000,000
Total aggregate lender commitment amount$1,100,000  $1,100,000  $1,200,000  

(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 $5.0 million and $5.9 million as of June 30, 2020, and December 31, 2019, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis.
(1)
(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
Unamortized deferred financing costs attributable to the credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $6.3 million and $6.4 million as of September 30, 2019, and December 31, 2018, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.
(2)
Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018, was released during the three months ended March 31, 2019.

Senior Notes
As of September 30, 2019, the Company’s senior notes consisted of 6.125% Senior Secured Notes due 2022, 5.0%. Senior Notes due 2024, 5.625% Senior Notes due 2025, 6.75% Senior Notes due 2026, and 6.625% Senior Notes due 2027 (“2027 Senior Notes”, and all senior notes collectively referred to as the “Senior Notes”). The SeniorSecured Notes, net of unamortized discount and deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of SeptemberJune 30, 2019, and December 31, 2018, 2020, consisted of the following:
 As of September 30, 2019 As of December 31, 2018
 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs
 (in thousands)
6.125% Senior Notes due 2022$476,796
 $3,170
 $473,626
 $476,796
 $3,921
 $472,875
5.0% Senior Notes due 2024500,000
 3,996
 496,004
 500,000
 4,688
 495,312
5.625% Senior Notes due 2025500,000
 5,130
 494,870
 500,000
 5,808
 494,192
6.75% Senior Notes due 2026500,000
 5,780
 494,220
 500,000
 6,407
 493,593
6.625% Senior Notes due 2027500,000
 6,834
 493,166
 500,000
 7,533
 492,467
Total$2,476,796
 $24,910
 $2,451,886
 $2,476,796
 $28,357
 $2,448,439
As of June 30, 2020
Principal AmountUnamortized Debt DiscountUnamortized Deferred Financing CostsPrincipal Amount, Net
(in thousands)
10.0% Senior Secured Notes due 2025$446,675  $(41,340) $(11,596) $393,739  
1.50% Senior Secured Convertible Notes due 2021 (1)
65,485  (3,592) (349) 61,544  
Total$512,160  $(44,932) $(11,945) $455,283  

(1) As discussed above, as required by the 2021 Notes Indenture and as permitted by the Credit Agreement, as the Company issued Permitted Second Lien Debt upon the closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured.
2025 Senior Secured Notes. On June 17, 2020, the Company issued $446.7 million in aggregate principal amount of 2025 Senior Secured Notes due January 15, 2025. The Company incurred fees of $11.7 million, which are being amortized as deferred financing costs over the life of the 2025 Senior Secured Notes. Upon the issuance of the 2025 Senior Secured
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Notes, the Company recorded $405.0 million as the initial carrying amount, which approximated their fair value at issuance. The excess of the principal amount of the 2025 Senior Secured Notes over its fair value was recorded as a debt discount. The debt discount and deferred financing costs are amortized to interest expense through the maturity date.
In connection with the issuance of the 2025 Senior Secured Notes, the Company entered into an indenture dated as of June 17, 2020 with UMB Bank, N.A., as trustee, governing the 2025 Senior Secured Notes (“2025 Notes Indenture”). The Company may redeem some or all of its 2025 Senior Secured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the 2025 Notes Indenture.
The 2025 Senior Secured Notes are senior obligations of the Company, secured on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement and equal in priority with the 2021 Senior Secured Convertible Notes. The 2025 Senior Secured Notes rank senior in right of payment with all of the Company’s existing and any future unsecured senior or subordinated debt.
2021 Senior Secured Convertible Notes. Upon issuance of the 2025 Senior Secured Notes, which was Permitted Second Lien Debt, as required by the 2021 Notes Indenture, and as permitted by the Credit Agreement, the 2021 Senior Convertible Notes became secured senior obligations of the Company on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement and equal in priority with the 2025 Senior Secured Notes. The 2021 Senior Secured Convertible Notes rank senior in right of payment to all of the Company’s existing and any future unsecured senior or subordinated debt. During the second quarter of 2020, pursuant to the Third Supplemental Indenture, the Company agreed to satisfy any conversion obligation solely in cash, resulting in reclassification of the fair value of the equity components out of additional paid-in capital. Please refer to Note 5 - Long-Term Debt in the 2019 Form 10-K for additional detail on the Company’s 2021 Senior Convertible Notes and associated capped call transactions.
On June 17, 2020, the Company retired $107.0 million in aggregate principal amount of its 2021 Senior Convertible Notes that were exchanged in the Private Exchange. As a result, the Company paid $740,000 of accrued and unpaid interest and recognized $6.1 million and $593,000 of previously unamortized debt discount and deferred financing costs, respectively, associated with the retired 2021 Senior Convertible Notes.
The 2021 Senior Secured Convertible Notes were not convertible at the option of holders as of June 30, 2020, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the 2021 Senior Secured Convertible Notes did not exceed the principal amount. The remaining debt discount and debt-related issuance costs are being amortized to the principal value of the 2021 Senior Secured Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the 2021 Senior Secured Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.6 million and $2.7 million for the three months ended June 30, 2020, and 2019, respectively, and totaled $5.4 million for each of the six months ended June 30, 2020, and 2019.
Senior Unsecured Notes. Senior Unsecured Notes, net of unamortized deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of June 30, 2020, and December 31, 2019, consisted of the following:
As of June 30, 2020As of December 31, 2019
Principal AmountUnamortized Deferred Financing CostsPrincipal Amount, NetPrincipal AmountUnamortized Deferred Financing CostsPrincipal Amount, Net
(in thousands)
6.125% Senior Notes due 2022$294,346  $1,494  $292,852  $476,796  $2,920  $473,876  
5.0% Senior Notes due 2024344,661  2,278  342,383  500,000  3,766496,234
5.625% Senior Notes due 2025349,118  3,108  346,010  500,000  4,903495,097
6.75% Senior Notes due 2026419,235  4,321  414,914  500,000  5,571494,429
6.625% Senior Notes due 2027416,791  5,114  411,677  500,000  6,601493,399
1.50% Senior Convertible Notes due 2021 (1)(2)
—  —  —  172,500  15,237  157,263
Total$1,824,151  $16,315  $1,807,836  $2,649,296  $38,998  $2,610,298  

(1) Unamortized deferred financing costs attributable to the 2021 Senior Convertible Notes include $13.9 million related to the unamortized debt discount as of December 31, 2019.
(2) As discussed above, as required by the 2021 Notes Indenture and as permitted by the Credit Agreement, as the Company issued Permitted Second Lien Debt upon the closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured.
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The senior unsecured notes listed above (collectively referred to as “Senior Unsecured Notes,” and together with the Senior Secured Notes, “Senior 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, 2019, 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.
On July 16, 2018, the Company redeemed its 6.50% Senior Notes due 2021 (“2021 Senior Notes”) which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 2027 Senior Notes, which resulted in the receipt of net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. The proceeds received from the issuance of the 2027 Senior Notes were used to fund the cash tender offer and redemption of all of the Company’s 6.50% Senior Notes due 2023 (“2023 Senior Notes”) and a portion of its 2022 Senior Notes during the third quarter of 2018. The Company paid total consideration, including accrued interest, of $497.8 million to complete these transactions. As a result of the redemption of the 2021 Senior Notes, and the cash tender offer and redemption of all of the 2023 Senior Notes and a portion of the 2022 Senior Notes, the Company recorded a combined loss on extinguishment of debt of $26.7 million for the quarter ended September 30, 2018.  This amount included combined premiums paid of $20.4 million and $6.3 million of accelerated unamortized deferred financing costs for the redemption. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of our 2018 Form 10-K for additional discussion.
Senior Convertible Notes
The Company’s senior convertible notes consist of $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible 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. Please refer to Note 5 - Long-Term Debt in the 20182019 Form 10-K for additional detail on the Company’s Senior ConvertibleUnsecured Notes.
On June 17, 2020, the Company retired $611.9 million in aggregate principal amount of its Senior Unsecured Notes that were exchanged in the Exchange Offers. As a result, the Company paid $8.1 million of accrued and unpaid interest and recognized $5.0 million of previously unamortized deferred financing costs associated capped call transactions.
with the retired Senior Unsecured Notes. The Company cancelled all retired Senior ConvertibleUnsecured Notes were not convertible at the option of holders as of September 30, 2019, or through the filing of this report. Notwithstanding the inability to convert, the if-converted valueupon closing of the Exchange Offers.
During the first quarter of 2020, the Company repurchased a total of $40.7 million in aggregate principal amount of its 2022 Senior Convertible Notes asin open market transactions for a total settlement amount, excluding accrued interest, of September 30, 2019, did not exceed$28.3 million. In connection with the principal amount. Therepurchase, the Company recorded a gain on extinguishment of 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 $2.8 million and $2.6$12.2 million for the three months ended September 30, 2019, and 2018, respectively, and totaled $8.2March 31, 2020. This amount included discounts realized upon repurchase of $12.4 million and $7.8 million for the nine months ended September 30, 2019, and 2018, respectively.

There have been no changes to the initial net carrying amountpartially offset by approximately $235,000 of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets since issuance. The Senior Convertible Notes, net ofaccelerated unamortized discount and deferred financing costs line on the accompanying balance sheets as of September 30, 2019, and December 31, 2018, consisted of the following:costs. The Company canceled all repurchased 2022 Senior Notes upon cash settlement.
 As of September 30, 2019 As of December 31, 2018
 (in thousands)
Principal amount of Senior Convertible Notes$172,500
 $172,500
Unamortized debt discount(16,012) (22,313)
Unamortized deferred financing costs(1,605) (2,293)
Senior Convertible Notes, net of unamortized discount and deferred financing costs$154,883
 $147,894

Covenants
The Company is subject to certain covenants under the indentureCredit Agreement and the indentures governing the Senior ConvertibleSecured Notes and the Senior Unsecured Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted payments including dividends, sell assets, 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, create liens that secure debt, enter into transactions with affiliates, and merge or consolidate with another company. The Company was in compliance with all such covenants as of SeptemberJune 30, 2019,2020, and through the filing of this report.
Capitalized Interest
Capitalized interest costs for the three months ended SeptemberJune 30, 2020, and 2019, and 2018, were $4.2totaled $4.1 million and $5.2$5.0 million, respectively, and totaled $6.8 million and $9.9 million for the ninesix months ended SeptemberJune 30, 2019,2020, and 2018, were $14.1 million and $15.7 million,2019, respectively. The amount of interest the Company capitalizes generally fluctuates based on the amount borrowed, the Company’s capital program, and the timing and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred.
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 20182019 Form 10-K.10-K. Please refer to Note 6 - Commitments and Contingencies in the 20182019 Form 10-K for additional discussion of the Company’s commitments.
DeliveryDrilling Rig Service Contracts. During the first half of 2020, and Purchase Commitments. Duringthrough the filing of this report, the Company amended certain of its drilling rig contracts resulting in the reduction of day rates and potential early termination fees and the extension of contract terms. As of the filing of this report, the Company’s drilling rig commitments totaled $17.6 million under contract terms extending through the second quarter of 2019, the Company executed an amendment to its existing sand sourcing agreement that created certain commitments and potential penalties that vary based on the amount of sand the Company uses in well completions occurring in a particular area. This amended sand sourcing agreement expires on December 31, 2023. As of September 30, 2019, potential penalties under this sand sourcing agreement range from 0 to a maximum of $10.0 million. The Company does not expect to incur material penalties with regard to this agreement.
Drilling Rig and Completion Service Contracts. The Company entered into new and amended drilling rig and well completion service contracts during the nine months ended September 30, 2019. As of September 30, 2019, the Company’s drilling rig and completion service contract commitments totaled $57.1 million.2021. If all of these contracts were terminated as of September 30, 2019,the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $38.1$9.0 million in early termination fees. Excluded from these amounts are variable commitments and potential penalties determined by the number of completion crews the Company has in operation in a particular area under a completion service arrangement. As of September 30, 2019, potential penalties under this completion service arrangement, which expires on December 31, 2023, range from 0 to a maximum of $14.3 million. The Company does not expect to incur material penalties with regard to its drilling rig and completion service contracts.
Electrical Power Purchase Contracts.Drilling and Completion Commitments. During the second quarterfirst half of 2019,2020, the Company entered into a fixed price contract foran agreement that includes minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2021, the purchase of electrical power that increasedCompany will be required to pay liquidated damages based on the purchase commitment under an existing agreement.difference between the actual footage drilled and completed and the minimum requirements. As of SeptemberJune 30, 2019,2020, the liquidated damages could range from 0 to a maximum of $39.5 million, with the maximum exposure assuming no additional development activity occurred prior to March 31, 2021. The Company also entered into an agreement that includes a minimum number of wells drilled and completed on certain existing leases. If these minimum requirements are not satisfied by December 31, 2021, the Company hadwill be required to pay liquidated damages based on the difference between the actual number of wells drilled and completed and the minimum requirements. As of June 30, 2020, the liquidated damages could range from 0 to a commitmentmaximum of $11.5 million, with the maximum exposure assuming no additional development activity occurred prior to purchase electrical power through 2027 with a total remaining obligation of $55.1 million.December 31, 2021. As of the filing of this report, the Company expects to meet this commitment.its obligations under both agreements.
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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. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Note 7 - Compensation Plans
Equity Incentive Compensation Plan
As of SeptemberJune 30, 2019, 4.12020, 4.2 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”).
Performance Share Units
The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity incentive compensation program.Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0 to 2 times the number of PSUs awarded and is determined based on certain settlement criteria over a three-year performance period. PSUs 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 that were granted in 2016 and 2017, which the Company determined to be equity awards, the settlement criteria included a combination of the Company’s Total Shareholder Return (“TSR”) on an absolute basis, and the Company’s TSR relative to the TSR of certain peer companies over the associated three-year performance period. The fair value of the PSUs granted in 2016 and 2017 was measured on the applicable grant datesdate using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). As these awards depend entirely on market-based settlement criteria, the associated compensation expense is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards.
For PSUs granted in 2018 and 2019, the settlement criteria includedinclude a combination of the Company’s TSR relative to the 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 stipulate that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is 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 2018 and 2019 was measured on the applicable grant dates using the GBM Model, with the assumption that the associated CRTCI performance condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs granted in 2018 and 2019 is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. 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 CRTCI performance relative to the applicable peer companies.
The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was $2.9$2.8 million and $3.0$2.9 million for the three months ended SeptemberJune 30, 2019,2020, and 2018,2019, respectively, and was $8.6$5.4 million and $7.7$5.7 million for the ninesix months ended SeptemberJune 30, 2019,2020, and 2018,2019, respectively. As of SeptemberJune 30, 2019,2020, there was $19.7$10.0 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2022.
A summary of There were no material changes to the statusoutstanding and activity of non-vested PSUs forduring the ninesix months ended SeptemberJune 30, 2019, is presented in the following table:2020.
 
PSUs (1)
 Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year1,711,259
 $20.68
Granted793,125
 $12.80
Vested(346,021) $26.31
Forfeited(40,999) $17.96
Non-vested at end of quarter2,117,364
 $16.86

(1)
The number of awards assumes a multiplier of 1. The final number of shares of common stock issued may vary depending on the three-year performance multiplier which ranges from 0 to 2.
During the nine months ended SeptemberSubsequent to June 30, 2019,2020, the Company issued 793,125 PSUs with a grant date fair value of $10.2 million. In addition to the settlement criteria described above, the 2019 Performance Share Unit Award Agreement also stipulates that if either the Company’s absolute TSR, or absolute CRTCI, is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs shall be capped at 1 times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to the peer group. During the nine months ended September 30, 2019, the Company settled all PSUs that were granted in 2016,2017, which earned a 0.9 times multiplier, by issuing 485,060 net shares of the Company’s common stock in accordance with 0the terms of the applicable PSU awards. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. As a result, 215,451 shares issuedwere withheld to satisfy income and payroll tax withholding obligations that occurred upon settlement becausedelivery of the grant settled at a 0 multiplier.shares underlying those PSUs.
Employee Restricted Stock Units
The Company grants restricted stock units (“RSUs”) to eligible persons as part of its long-term equity incentive compensation program.Equity Plan. Each RSU represents a right to receive 1 share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and

exploration expense over the vesting periodsgenerally vest one-third of the respective awards. RSUs granted to employees generally vest one-thirdtotal grant on each anniversary date of the grant over a three-year 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 day of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting
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periods of the respective awards. Total compensation expense recorded for employee RSUs was $2.9$2.7 million and $3.0$2.8 million for the three months ended SeptemberJune 30, 2019,2020, and 2018,2019, respectively and was $8.4$5.3 million and $8.0$5.5 million for the ninesix months ended SeptemberJune 30, 2019,2020, and 2018,2019, respectively. As of SeptemberJune 30, 2019,2020, there was $21.4$10.8 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2022.
A summary of There were no material changes to the statusoutstanding and activity of non-vested RSUs granted to employees forduring the ninesix months ended SeptemberJune 30, 2019, is presented in the following table:2020.
 RSUs Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year1,243,163
 $21.50
Granted978,932
 $12.36
Vested(466,535) $21.93
Forfeited(111,188) $19.94
Non-vested at end of quarter1,644,372
 $16.04

During the nine months ended SeptemberSubsequent to June 30, 2019, the Company granted 978,932 RSUs with a grant date fair value of $12.1 million. Also, during the nine months ended September 30, 2019,2020, the Company settled 466,535587,088 RSUs that related to awards granted in previous years. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. As a result, the Company issued 334,399420,562 net shares of common stock upon settlement of the awards. The remaining 166,526 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those RSUs.
Director Shares
During the second quarters of 2019,2020, and 2018,2019, the Company issued 96,719267,576 and 58,57296,719 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. Shares issued during the second quarter of 20192020 will fully vest on December 31, 2019.2020. Shares issued during the second quarter of 20182019 fully vested on December 31, 2018. The Company did not issue any director shares during the third quarters of 2019, or 2018.2019.
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 excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. There were 184,079297,013 and 100,249184,079 shares issued under the ESPP during the nine months ended September 30,second quarters of 2020, and 2019, and 2018, respectively. Total proceeds to the Company for the issuance of these shares was $2.0 million$947,000 and $1.9$2.0 million for the ninesix months ended SeptemberJune 30, 2019,2020, and 2018,2019, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.
Note 8 - Pension Benefits
Pension Plans
The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (the “Qualified(“Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified(“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 January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen will continue to earn benefits.

Components of Net Periodic Benefit Cost for the Pension Plans
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in thousands)
Components of net periodic benefit cost:       
Service cost$1,395
 $1,683
 $4,186
 $5,048
Interest cost699
 657
 2,094
 1,967
Expected return on plan assets that reduces periodic pension benefit cost(393) (466) (1,180) (1,397)
Amortization of prior service cost4
 4
 13
 13
Amortization of net actuarial loss239
 331
 718
 995
Net periodic benefit cost$1,944
 $2,209
 $5,831
 $6,626

For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in thousands)
Components of net periodic benefit cost:
Service cost$863  $1,108  $2,258  $2,791  
Interest cost480  739  1,178  1,395  
Expected return on plan assets that reduces periodic pension benefit cost(474) (321) (867) (787) 
Amortization of prior service cost5  5  9  9  
Amortization of net actuarial loss235  147  475  479  
Net periodic benefit cost$1,109  $1,678  $3,053  $3,887  
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. The service cost component of net periodic benefit cost for the Pension Plans is presented as an operating expense within the general and administrative and exploration expense line items on the accompanying statements of operations while the other components of net periodic benefit cost for the Pension Plans are presented as non-operating expenses within the other non-operating income (expense),expense, net line item on the accompanying statements of operations.
17

Contributions
As of the filing of this report, the Company has contributed $7.2$4.6 million to the Qualified Pension Plan in 2019 and does not expect to make additional contributions for the remainder of 2019.2020.
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 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. PotentiallyAs of June 30, 2019, potentially dilutive securities for this calculation consistconsisted primarily of non-vested RSUs, contingent PSUs, and shares into which the 2021 Senior Convertible Notes arewere convertible, which arewere measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price applicable to the 2021 Senior Convertible Notes for the three and ninesix months ended SeptemberJune 30, 2019, and 2018, and therefore, the 2021 Senior Convertible Notes had no dilutive impact. On April 29, 2020, pursuant to the Third Supplemental Indenture, the Company agreed that it will satisfy any conversion obligation with respect to the 2021 Senior Convertible Notes solely in cash. As a result, the Company’s 2021 Senior Secured Convertible Notes are no longer convertible into shares of the Company’s common stock and thus, were not considered to be a potentially dilutive instrument as of June 30, 2020.
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 outstanding common stock, at an exercise price of $0.01 per share, as discussed in Note 5 - Long-Term Debt. The Warrant Agreement dated as of June 17, 2020 (“Warrant Agreement”), states that the warrants are only exercisable upon the Triggering Date, as defined in Note 11 - Fair Value Measurements. The warrants were not exercisable during the six months ended June 30, 2020, and therefore had 0 dilutive impact. Please refer toNote 11 - Fair Value Measurements for additional detail regarding the terms of the warrants.
As of June 30, 2020, potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and warrants, which are measured using the treasury stock method. Please refer to Note 7 - Compensation Plans and Note 11 - Fair Value Measurements in this report, and Note 9 - Earnings Per Share in the 20182019 Form 10-K for additional detail on these potentially dilutive securities.
When the Company recognizes a net loss from continuing operations, 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 anti-dilutive securities for the periods presented:
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in thousands)
Anti-dilutive—
 2,433
 707
 —


For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in thousands)
Anti-dilutive701—877715
The following table sets forth the calculations of basic and diluted net income (loss) per common share:
For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,		For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2019 2018 2019 20182020201920202019
(in thousands, except per share data)(in thousands, except per share data)
Net income (loss)$42,234
 $(135,923) $(84,946) $198,675
Net income (loss)$(89,252) $50,388  $(501,147) $(127,180) 
       
Basic weighted-average common shares outstanding112,804
 112,107
 112,441
 111,836
Basic weighted-average common shares outstanding113,008112,262113,015112,257
Dilutive effect of non-vested RSUs and contingent PSUs530
 —
 —
 1,764
Dilutive effect of non-vested RSUs and contingent PSUs—670——
Diluted weighted-average common shares outstanding113,334
 112,107
 112,441
 113,600
Diluted weighted-average common shares outstanding113,008112,932113,015112,257
       
Basic net income (loss) per common share$0.37
 $(1.21) $(0.76) $1.78
Basic net income (loss) per common share$(0.79) $0.45  $(4.43) $(1.13) 
Diluted net income (loss) per common share$0.37
 $(1.21) $(0.76) $1.75
Diluted net income (loss) per common share$(0.79) $0.45  $(4.43) $(1.13) 
18

Note 10 - Derivative Financial Instruments
Summary of Oil, Gas, and NGL Derivative Contracts in Place
The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of SeptemberJune 30, 2019,2020, all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas production, and swap arrangements for 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 also entered into fixed price oil 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 volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEXNew York Mercantile Exchange (“NYMEX”) WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also hasprices, and basis swapsswap contracts with fixed price differentials between 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. The Company has also entered into crude 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 SeptemberJune 30, 2019,2020, the Company had commodity derivative contracts outstanding through the fourth quarter of 2022 as summarized in the tables below.
Oil Swaps

Contract Period
 NYMEX WTI Volumes 
Weighted-Average
 Contract Price

Contract Period
NYMEX WTI Volumes
Weighted-Average
 Contract Price
 (MBbl) (per Bbl)(MBbl)(per Bbl)
Fourth quarter 2019 1,685
 $61.38
2020 7,441
 $59.64
Third quarter 2020Third quarter 20203,361  $56.43  
Fourth quarter 2020Fourth quarter 20204,397  $57.03  
2021202113,467  $39.65  
202220221,276  $41.75  
Total 9,126
  Total22,501  
Oil Collars
Contract PeriodNYMEX WTI VolumesWeighted-Average Floor PriceWeighted-Average Ceiling Price
(MBbl)(per Bbl)(per Bbl)
Third quarter 20201,252  $55.00  $62.90  
Fourth quarter 2020610  $55.00  $61.90  
2021329  $55.00  $56.70  
Total2,191  
19
Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price
  (MBbl) (per Bbl) (per Bbl)
Fourth quarter 2019 3,168
 $50.54
 $62.49
2020 6,010
 $55.00
 $62.95
2021 329
 $55.00
 $56.70
Total 9,507
    


Oil Basis Swaps
Contract Period WTI Midland-NYMEX WTI Volumes 
Weighted-Average
 Contract Price (1)
 NYMEX WTI-ICE Brent Volumes 
Weighted-Average
Contract Price (2)
Contract PeriodWTI Midland-NYMEX WTI Volumes
Weighted-Average
 Contract Price (1)
NYMEX WTI-ICE Brent Volumes
Weighted-Average Contract Price (2)
 (MBbl) (per Bbl) (MBbl) (per Bbl)(MBbl)(per Bbl)(MBbl)(per Bbl)
Fourth quarter 2019 3,338
 $(2.87) —
 $—
2020 14,090
 $(0.73) 2,750
 $(8.03)
Third quarter 2020Third quarter 20203,607  $(0.62) 920  $(8.01) 
Fourth quarter 2020Fourth quarter 20204,087  $(0.38) 920  $(8.01) 
2021 3,708
 $0.33
 3,650
 $(7.86)202111,527  $0.87  3,650  $(7.86) 
2022 —
 $—
 3,650
 $(7.78)20229,500  $1.15  3,650  $(7.78) 
Total 21,136
   10,050
  Total28,721  9,140  

(1)
(1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
(2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
Oil Roll Differential Swaps

Contract Period
NYMEX WTI VolumesWeighted-Average
Contract Price
(MBbl)(per Bbl)
Third quarter 20203,077  $(1.34) 
Fourth quarter 20202,503  $(1.18) 
20214,002  $(0.52) 
Total9,582  
Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
(2)
Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
Gas Swaps
Contract PeriodIF HSC VolumesWeighted-Average
Contract Price		WAHA VolumesWeighted-Average Contract Price
(BBtu)(per MMBtu)(BBtu)(per MMBtu)
Third quarter 20204,493  $2.41  4,628  $1.08  
Fourth quarter 20209,327  $2.39  4,872  $1.21  
202141,736  $2.38  20,676  $1.52  
20226,104  $2.23  2,681  $1.90  
Total (1)
61,660  32,857  

Contract Period IF HSC Volumes 
Weighted-Average
 Contract Price
 WAHA Volumes Weighted-Average Contract Price
  (BBtu) (per MMBtu) (BBtu) (per MMBtu)
Fourth quarter 2019 14,433
 $2.88
 2,962
 $1.75
2020 11,773
 $2.87
 4,977
 $1.70
Total (1)
 26,206
   7,939
  
(1) ____________________________________________The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of June 30, 2020, WAHA volumes were comprised of 71 percent IF WAHA and 29 percent GD WAHA.
(1)
The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of September 30, 2019, WAHA volumes were comprised of 56 percent IF WAHA and 44 percent GD WAHA.
Gas Collars
Contract Period IF HSC Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price
  (BBtu) (per MMBtu) (per MMBtu)
Fourth quarter 2019 4,818
 $2.50
 $2.83
Total 4,818
    
NGL Swaps
  OPIS Ethane Purity 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
  (MBbl)(per Bbl) (MBbl)(per Bbl) (MBbl)(per Bbl) (MBbl)(per Bbl) (MBbl)(per Bbl)
Fourth quarter 2019 896
$12.36
 660
$31.60
 39
$35.64
 29
$35.70
 50
$50.93
2020 711
$11.38
 1,187
$23.58
 —
$—
 —
$—
 —
$—
Total 1,607
  1,847
  39
  29
  50
 

OPIS Propane Mont Belvieu Non-TET
Contract PeriodVolumesWeighted-Average Contract Price
(MBbl)(per Bbl)
Third quarter 2020409  $22.33  
Fourth quarter 2020466  $22.29  
Total875  
Commodity Derivative Contracts Entered Into Subsequent to SeptemberJune 30, 20192020
Subsequent to SeptemberJune 30, 2019,2020, the Company entered into the following commodity derivative contracts:
•fixed price NYMEX WTI oil swap contracts for 2021 through the thirdfourth quarter of 20202022 for a total of 0.93.7 MMBbl of oil production at a weighted-average contract price of $51.61$43.29 per Bbl;
•fixed price IF HSC gasWTI Midland-NYMEX WTI oil basis swap contracts for the second through fourth quarters of 20202021 for a total of 9,725 BBtu2.3 MMBbl of gasoil production at a weighted-average contract price of $2.28$0.21 per MMBtu;Bbl;
20

•a fixed price IFGD WAHA gas swap contractscontract for 2020 andthe fourth quarter of 2021 for a total of 12,229920 BBtu of gas production at a weighted-average contract price of $1.06$1.99 per MMBtu; and

•a fixed price OPIS Propane Mont Belvieu Non-TET swap contractscontract for 20202021 for a total of 0.50.4 MMBbl of propane production at a weighted-average contract price of $19.27$19.74 per Bbl.
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, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the commodity derivative contracts was a net asset of $137.9$183.7 million and $158.3$21.5 million as of SeptemberJune 30, 2019,2020, and December 31, 2018,2019, respectively.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:
As of September 30, 2019 As of December 31, 2018As of June 30, 2020As of December 31, 2019
(in thousands)(in thousands)
Derivative assets:   Derivative assets:
Current assets$143,142
 $175,130
Current assets$211,582  $55,184  
Noncurrent assets38,571
 58,499
Noncurrent assets34,390  20,624  
Total derivative assets$181,713
 $233,629
Total derivative assets$245,972  $75,808  
Derivative liabilities:   Derivative liabilities:
Current liabilities$37,798
 $62,853
Current liabilities$38,250  $50,846  
Noncurrent liabilities6,014
 12,496
Noncurrent liabilities24,028  3,444  
Total derivative liabilities$43,812
 $75,349
Total derivative liabilities$62,278  $54,290  
Offsetting of Derivative Assets and Liabilities
As of SeptemberJune 30, 2019,2020, and December 31, 2018,2019, 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 Derivative Liabilities
As of As ofDerivative Assets as ofDerivative Liabilities as of
September 30,
2019
 December 31, 2018 
September 30,
2019
 December 31, 2018June 30, 2020December 31, 2019June 30, 2020December 31, 2019
(in thousands)(in thousands)
Gross amounts presented in the accompanying balance sheets$181,713
 $233,629
 $(43,812) $(75,349)Gross amounts presented in the accompanying balance sheets$245,972  $75,808  $(62,278) $(54,290) 
Amounts not offset in the accompanying balance sheets(43,812) (56,041) 43,812
 56,041
Amounts not offset in the accompanying balance sheets(62,278) (35,075) 62,278  35,075  
Net amounts$137,901
 $177,588
 $—
 $(19,308)Net amounts$183,694  $40,733  $—  $(19,215) 
21


The following table summarizes the commodity components of the derivative settlement (gain) loss, as well as the components of the net derivative (gain) loss line item presented in the accompanying statements of operations:
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in thousands)
Derivative settlement (gain) loss:       
Oil contracts$2,246
 $16,798
 $14,304
 $61,976
Gas contracts(12,210) 802
 (13,744) (4,851)
NGL contracts(14,758) 23,118
 (24,403) 44,786
Total derivative settlement (gain) loss$(24,722) $40,718
 $(23,843) $101,911
        
Net derivative (gain) loss:       
Oil contracts$(83,984) $110,413
 $67,261
 $146,781
Gas contracts(4,228) 4,309
 (36,337) 21,299
NGL contracts(12,677) 63,304
 (34,387) 81,224
Total net derivative (gain) loss$(100,889) $178,026
 $(3,463) $249,304

For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in thousands)
Derivative settlement (gain) loss:
Oil contracts$(138,606) $10,689  $(192,188) $12,058  
Gas contracts(1,054) (5,668) (15,679) (1,534) 
NGL contracts(2,868) (9,111) (8,098) (9,645) 
Total derivative settlement (gain) loss$(142,528) $(4,090) $(215,965) $879  
Net derivative (gain) loss:
Oil contracts$151,250  $(34,552) $(391,290) $151,245  
Gas contracts8,261  (25,996) 14,989  (32,109) 
NGL contracts7,689  (19,107) (1,839) (21,710) 
Total net derivative (gain) loss$167,200  $(79,655) $(378,140) $97,426  
Credit Related Contingent Features
As of SeptemberJune 30, 2019,2020, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 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.
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 unobservableunobservable.
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 SeptemberJune 30, 2019:2020:

Level 1
Level 2
Level 3

(in thousands)
Assets:     
Derivatives (1)
$—
 $181,713
 $—
Liabilities:     
Derivatives (1)
$—
 $43,812
 $—
__________________________________________
Level 1Level 2Level 3
(in thousands)
Assets:
Derivatives (1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.$— $245,972 $— 
Liabilities:
Derivatives (1)
$— $62,278 $— 


(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
22

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 wereare classified within the fair value hierarchy as of December 31, 2018:2019:
 Level 1 Level 2 Level 3
 (in thousands)
Assets:     
Derivatives (1)
$—
 $233,629
 $—
Liabilities:     
Derivatives (1)
$—
 $75,349
 $—
____________________________________________
Level 1Level 2Level 3
(in thousands)
Assets:
Derivatives (1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.$— $75,808 $— 
Liabilities:
Derivatives (1)
$— $54,290 $— 

(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, and to Note 11 - Fair Value Measurements in the 20182019 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 had 0 assets included in total property and equipment, net, measured at fair value as of June 30, 2020, or December 31, 2019.
Proved oil and gas properties.properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and thean income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties through the application ofusing a discount ratesrate, price and pricecost forecasts, representative of the current operating environment,and certain reserve risk-adjustment factors, as selected by the Company’s management.
Unproved The Company uses a discount rate that represents a current market-based weighted average cost of capital. The prices for oil and gas properties.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 forecasted using Oil Price Information Service (“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. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties.
Other Property and Equipment. Unproved oilOther property and gas propertyequipment 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,other property and equipment, the Company uses aan income valuation technique or market approach which takes into accountdepending on the following significant assumptions: remaining lease terms,quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future development plans, risk-weighted potential resource recovery, estimated reserve values,cash flows associated with the assets, and estimated acreagefixed costs necessary to operate and maintain the assets.
NaN proved property impairment expense was recorded during the three months ended June 30, 2020. For the six months ended June 30, 2020, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities due to the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices. The Company used a discount rate of 11 percent in its calculation of the present value of expected future cash flows based on price(s) received for similar, recent acreage transactions by the Companyprevailing market-based weighed average cost of capital as of March 31, 2020. NaN proved property impairment expense was recorded during the three or other market participants. six months ended June 30, 2019.
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The Company recordedfollowing table presents impairment of oil and gas properties expense and abandonment and impairment of unproved properties expense of $6.3 million and $25.1 millionrecorded during the three and nine months ended September 30, 2019, respectively, and $9.1 million and $26.6 million during three and nine months ended September 30, 2018, respectively. periods presented:
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions)
Impairment of proved oil and gas properties and related support equipment$—  $—  $956.7  $—  
Abandonment and impairment of unproved properties (1)
8.8  12.4  41.9  18.8  
Impairment (2)
$8.8  $12.4  $998.5  $18.8  

(1) These expensesimpairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks.
Properties held for sale. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by The balances in the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-downunproved oil and subsequent changes to the fair value less estimated cost to sell is included within the net gain on divestiture activitygas properties line item inon the accompanying statementsbalance sheets as of operations.June 30, 2020, and December 31, 2019, are recorded at carrying value.
(2) Amounts may not calculate due to rounding.
Please refer to Note 1 - Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the 20182019 Form 10-K for more information regarding the Company’s approach in determining the fair value of its properties.

Long-Term Debt
The following table reflects the fair value of the Company’s unsecured senior noteSenior Note 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 SeptemberJune 30, 2019,2020, or December 31, 2018,2019, 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, 2019 As of December 31, 2018
 Principal Amount Fair Value Principal Amount Fair Value
 (in thousands)
6.125% Senior Notes due 2022$476,796
 $459,321
 $476,796
 $452,336
5.0% Senior Notes due 2024$500,000
 $448,950
 $500,000
 $439,265
5.625% Senior Notes due 2025$500,000
 $431,335
 $500,000
 $436,460
6.75% Senior Notes due 2026$500,000
 $440,000
 $500,000
 $448,305
6.625% Senior Notes due 2027$500,000
 $432,500
 $500,000
 $442,500
1.50% Senior Convertible Notes due 2021$172,500
 $156,706
 $172,500
 $158,614
As of June 30, 2020As of December 31, 2019
Principal AmountFair ValuePrincipal AmountFair Value
(in thousands)
6.125% Senior Unsecured Notes due 2022$294,346  $214,873  $476,796  $481,564  
5.0% Senior Unsecured Notes due 2024$344,661  $190,477  $500,000  $479,815  
5.625% Senior Unsecured Notes due 2025$349,118  $185,033  $500,000  $475,835  
6.75% Senior Unsecured Notes due 2026$419,235  $213,286  $500,000  $494,860  
6.625% Senior Unsecured Notes due 2027$416,791  $206,566  $500,000  $493,750  
10.0% Senior Secured Notes due 2025$446,675  $424,064  $—  $—  
1.5% Senior Convertible Notes due 2021(1)
$—  $—  $172,500  $164,430  
1.5% Senior Secured Convertible Notes due 2021(1)
$65,485  $60,246  $—  $—  

(1) The Company’s 2021 Senior Convertible Notes became secured in the second quarter of 2020 upon closing of the Exchange Offers. Please refer to Note 5 - Long-Term Debt for additional information.
The carrying value of the Company’s revolving credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.
Warrants
As discussed in Note 5 - Long-Term Debt, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, at an exercise price of $0.01 per share. The warrants are exercisable any time from and after the Triggering Date, as subsequently defined, until June 30, 2023. The Triggering Date is defined by the Warrant Agreement as the first trading day following five consecutive trading days on which the product of the number of shares of common stock issued and outstanding on four of the five trading days multiplied by the closing price per share of common stock for each such trading day exceeds $1.0 billion (“Triggering Date”). The warrants issued are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement if exercised. The warrants were not exercisable during the six months ended June 30, 2020, or through the filing of this report.
The fair value of the warrants on the issuance date was determined using a stochastic Monte Carlo simulation using the GBM Model. The Company evaluated the warrants under authoritative accounting guidance and determined that they should be classified as
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equity instruments. The warrants were recorded in additional paid-in capital on the accompanying balance sheets at a fair value of $21.5 million, with no recurring fair value measurement required.
Note 12 - Leases
Effective January 1, 2019, the Company adoptedASC Topic 842 which- Leases (“Topic 842”), requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of SeptemberJune 30, 2019,2020, the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases.
As outlined in Topic 842, aan ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that varywhich for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on actual usage or performance.
The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classificationthe nature and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair valueuse of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excludedin accordance with GAAP requirements.
Please refer to Note 12 - Leases in the initial measurement of2019 Form 10-K for more information regarding the ROU asset. CertainCompany's policy on leases, and assumptions and judgments made byin the Company when evaluating a contract that meets the definitioninitial and subsequent measurement of a lease under Topic 842 include:
Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception.
Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU assetassets and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company.liabilities.
Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately sevensix years. The weighted-average lease term remaining for these leases is approximately three years. Certain leases also contain optional extension periods that allow for terms to be extended for up to an

additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement.
Subsequent to initial measurement, costs associated Based on expectations for those agreements with the Company’s operatingearly termination options, there are no leases in which material early termination options are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to Note 1 - Summary of Significant Accounting Policies in the Company’s 2018 Form 10-K for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expectedreasonably certain to be made upon commencement ofexercised by the lease. Excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs.Company.
For the three and nine months ended SeptemberJune 30, 2020, and 2019, total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were $107.3$62.2 million and $422.4$139.8 million, respectively. For the six months ended June 30, 2020, and 2019, total lease costs were $135.0 million and $315.1 million, respectively. These totals do not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. Components of the Company’s total lease cost, whether capitalized or expensed, for the three and ninesix months ended SeptemberJune 30, 2020, and 2019, consisted of the following:
For the Three Months Ended June 30,For the Six Months Ended June 30,
2020201920202019
(in thousands)
Operating lease cost$4,453  $11,479  $11,287  $20,458  
Short-term lease cost (1)
36,630  102,085  80,202  237,002  
Variable lease cost (2)
21,136  26,198  43,470  57,606  
Total lease cost$62,219  $139,762  $134,959  $315,066  

(1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.
(2) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.
Right-of-use assets obtained in exchange for new operating lease liabilities totaled $745,000 for the three and six months ended June 30, 2020, and $10.5 million and $22.7 million for the three and six months ended June 30, 2019, were as follows:respectively.
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 For the Three Months Ended September 30, 2019 For the Nine Months Ended September 30, 2019
 (in thousands)
Operating lease cost$8,344
 $28,802
Short-term lease cost (1)
72,874
 309,876
Variable lease cost (2)
26,090
 83,696
Total lease cost (3)
$107,308
 $422,374

(1)
Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.
(2)
Variable lease payments include additional payments made that were notCash paid for amounts included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs and completion crews, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.
(3)
Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.
Other information related to the Company’s leasesmeasurement of lease liabilities for the ninesix months ended SeptemberJune 30, 2020, and 2019, was as follows:
 For the Nine Months Ended September 30, 2019
 (in thousands)
Cash paid for amounts included in the measurement of lease liabilities: 
Operating cash flows from operating leases$9,029
Investing cash flows from operating leases$20,256
Right-of-use assets obtained in exchange for new operating lease liabilities$24,014


For the Six Months Ended June 30,
20202019
(in thousands)
Operating cash flows from operating leases$6,065  $5,966  
Investing cash flows from operating leases$6,188  $14,808  
Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of SeptemberJune 30, 2019,2020, were as follows:
As of June 30, 2020
As of September 30, 2019(in thousands)
(in thousands)
2019 (remaining after September 30, 2019)$6,871
202020,427
2020 (remaining after June 30, 2020)2020 (remaining after June 30, 2020)$7,161  
202111,982
202112,938  
20225,712
20225,948  
20233,572
20233,602  
202420242,081  
Thereafter3,721
Thereafter1,640  
Total Lease payments$52,285
Total Lease payments$33,370  
Less: Imputed interest (1)
(5,098)
Less: Imputed interest (1)
(3,340) 
Total$47,187
Total$30,030  

(1)
(1) The weighted-average discount rate used to determine the operating lease liability as of June 30, 2020, was 6.9 percent.
The weighted-average discount rate used to determine the operating lease liability as of September 30, 2019 was 6.6 percent.
Amounts recorded on the accompanying balance sheets for operating leases as of SeptemberJune 30, 2020, and December 31, 2019, were as follows:
 As of September 30, 2019
 (in thousands)
Other noncurrent assets$44,438
  
Other current liabilities$21,804
Other noncurrent liabilities$25,384

As of June 30, 2020As of December 31, 2019
(in thousands)
Other noncurrent assets$27,778  $39,717  
Other current liabilities$12,597  $19,189  
Other noncurrent liabilities$17,433  $23,137  
As of SeptemberJune 30, 2019,2020, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements at the endsection of this itemreport for important information about these types of statements.
Overview of the Company
General Overview
We are an independentOur purpose is to make people’s lives better by responsibly producing energy company engagedsupplies, contributing to energy security and prosperity, and having a positive impact in the acquisition, exploration, development,communities where we live and productionwork. Our long-term vision is to sustainably grow value for all of oil, gas, and NGLsour stakeholders. We believe that in onshore North America, with operations currently focused in the state of Texas. Our strategic objective isorder to accomplish this vision, we must be a premier operator of top tier assets. We seek to maximize the value ofAt present, our assets by applying industry-leading technology and outstanding operational execution. Ourinvestment portfolio is comprised of unconventional resource prospects with expanding prospective drilling opportunities, which we believe provides for long-term production and reserves growth. We are focused on generating strong, full-cycle economic returns on our investmentshigh quality oil and maintaining a strong balance sheet.gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in South Texas.
Regional OverviewAreas of Operations
Our Midland Basin assets are located in the Permian region isBasin in West Texas and are comprised of approximately 80,000 net acres in the Midland Basin located in western Texas (“Midland Basin”). Operations inIn the second quarter of 2020, we focused on continuing to delineate, develop, and expand our Midland Basin are primarily focused on developingposition. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Lower Spraberry and Wolfcamp A and B intervals on our RockStar acreage in Howard and Martin Counties, Texas, and Lower and Middle Spraberry and Wolfcamp A and B intervals on our Sweetie Peck acreage in Upton and Midland Counties, Texas. We are also actively evaluating and testing additional formations and intervals within our RockStar position, including the Middle Spraberry, Wolfcamp D, and Dean.formations.
Our South Texas & Gulf Coast region is primarilyassets are comprised of approximately 163,000159,000 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on developing the Eagle Ford Shale Formationshale formation and testing additional intervals and formations, includingdelineating the Austin Chalk Formation.formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations includes acreage in oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.
ThirdSecond Quarter 2019 Highlights2020 Overview and Outlook for the Remainder of 20192020
The Pandemic continues to impact supply and demand for oil, gas, and NGLs, and thus our entire industry. The impacts of the Pandemic continue to be unpredictable. Future case surges or outbreaks could have further negative impacts on pricing, and as a result, we may be required to adjust our business plan which could include curtailing production. For additional detail, please refer to Risk Factors inPart II, Item 1A of this report and those risk factors previously disclosed in our 2019 Form 10-K.
We were impacted by the Pandemic and other macroeconomic events in the first and second quarters of 2020, most notably affecting the realized prices we receive for our production, and we expect to continue to be impacted by these events for the remainder of 2020. Despite continued negative impacts, we expect to maintain our current ability to sustain strong operational performance and financial stability. Given the dynamic nature of the Pandemic, we are unable to reasonably estimate the period of time that these market conditions will exist, the extent to which they will continue to impact our business, results of operations, and financial condition, or the timing of any subsequent recovery. Notwithstanding this uncertainty, we remain focused on maximizing returns and increasing the value of our top tier Midland Basin and South Texas assets. We expect to do this through continued development optimization exploration, and acquisitions.delineation. We believe theseour assets provide significant production growth potential and strong returns that should increaseare capable of providing internally generated cash flows andin low commodity price environments, which support our priorities of improving creditleverage metrics and maintaining strong financial flexibility. During the second quarter of 2020 and as a result of the Exchange Offers discussed in Note 5 - Long-Term Debt in Part I, Item 1 of this report, we reduced our outstanding debt by $218.7 million. Our financial risk management program has significantly reduced the impact of substantially lower oil prices in 2020, and as a result of this program we recorded an oil derivative settlement gain of $16.40 per barrel for the six months ended June 30, 2020. Our realized oil price before the effects of derivative settlements was $35.09 for the six months ended June 30, 2020. As of June 30, 2020, a majority of our expected oil production for the second half of 2020 is covered by derivative contracts at NYMEX equivalent prices greater than or equal to $55.00 per barrel. Please refer to Oil, Gas, and NGL Prices below for additional detail on the pricing effects of our derivative settlements. Also, in response to the current economic environment, we have renegotiated certain contracts resulting in realized cost savings that directly support our objective of maximizing cash flows. After the renegotiation of certain contracts and taking into account other cost reductions resulting from the current economic environment, we expect an approximate 25 percent reduction in the average cost per well for the remainder of 2020, compared to year-end 2019 estimates.
Sustainability is a key focus of our plans in terms of positioning ourselves financially to participate in future energy investment opportunities and executing our strategy of being a premier operator with high standards for corporate responsibility. We remain committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas. Our Board of Directors recently delegated its Nominating and Corporate Governance Committee the responsibility to oversee the development and implementation of the Company’s environmental and social policies, programs and initiatives, and renamed the committee the Environmental, Social and Governance Committee.
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Energy production was deemed an essential business amidst the Pandemic. The safety of our employees, contractors, and communities where we work is our first priority while we continue to work during the Pandemic. While the execution of our business operations requires certain individuals to be physically present at well site locations, substantially all of our office-based employees are working remotely to limit physical interactions to mitigate the spread of COVID-19. For individuals who are unable to perform their jobs remotely, we maintain and continually improve social distancing and sanitary measures at our physical locations, and we continue to communicate to and train all of our employees regarding best practices applicable to maintaining a healthy and safe work environment. Since these measures were initially implemented in the first quarter of 2020, we have continued to operate without significant disruptions to our business operations. Our pre-existing control environment and internal controls continue to be effective and we continue to address new risks directly related to the Pandemic as we identify them.
The information below summarizes our recent operating and financial performance and our expectations for the remainder of 2020, including our liquidity position.
OurWe entered 2020 with a total capital program budget between $825 million and $850 million. However, given the Pandemic and related circumstances discussed above, we reduced our 2020 capital program budget by approximately 25 percent for 2019, excluding acquisitions, is expectedthe full year 2020. Our financial and operational flexibility allows us to range from $1.00 billion to $1.05 billion.continually monitor the economic environment throughout the year and adjust our activity level as warranted. Our 2020 program remains concentratedfocused on developing our core assetsmost economic oil development projects in theboth our Midland Basin and South Texas with the majority of our 2019 capital allocated to our Midland Basin program. Drilling and completion activity on our South Texas acreage position was primarily funded by a third party as part of a joint development agreement. All wells subject to this agreement were completed as of September 30, 2019.assets. Please refer to Overview of Liquidity and Capital Resources below for additional discussion onof how we expect to fund our 20192020 capital program.
Financial and Operational Results. Average net daily production for the three months ended SeptemberJune 30, 2019,2020, was 134.9122.9 MBOE, compared with 130.2136.5 MBOE for the same period in 2018.2019. This increasedecrease was driven by an 11a 28 percent decrease in average net daily production volumes from our South Texas assets, partially offset by a six percent increase in average net daily production volumes from our Midland Basin assets. The overall decrease in production for the three months ended June 30, 2020, was primarily due to voluntary production curtailments, fewer net well completions during the three months ended June 30, 2020, compared with the same period in 2019, and deferral of production start-up of completed wells until June 2020, all of which were in response to low commodity prices in April and May of 2020. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased five60 percent, 3942 percent, and 4936 percent, respectively, for the three months ended SeptemberJune 30, 2019,2020, compared with the same period in 2018.2019. As a result of decreased commodity prices,production and pricing, oil, gas, and NGL production revenue decreased 1558 percent to $389.4$169.8 million for the three months ended SeptemberJune 30, 2019 from $458.42020, compared with $406.9 million for the same period in 2018. 2019.
We recorded a net derivative loss of $167.2 million and a net derivative gain of $100.9$79.7 million for the three months ended SeptemberJune 30, 2020, and 2019, compared to a net derivative loss of $178.0 million recorded for the same period in 2018.respectively. Included within these derivative amounts is a gain of $24.7$142.5 million on derivative contracts that settled during the three months ended SeptemberJune 30, 2019,2020, and a lossgain of $40.7$4.1 million for the same period in 2018. Together, these changes2019. Total production costs on a per BOE basis decreased 27 percent to $7.20 per BOE for the three months ended June 30, 2020, from $9.90 per BOE for the same period in 2019. Overall, financial and operational activities during the three months ended June 30, 2020, resulted in the following:
•net cash provided by operating activities of $114.3 million for the three months ended June 30, 2020, compared with $259.9 million for the same period in 2019;
•net incomeloss of $42.2$89.3 million, or $0.37$0.79 per diluted share, for the three months ended SeptemberJune 30, 2019,2020, compared to awith net lossincome of $135.9$50.4 million, or $1.21$0.45 per diluted share, for the same period in 2018;
2019. The net cash provided by operating activities of $203.2 millionloss for the three months ended SeptemberJune 30, 2019, compared with $229.72020, was primarily driven by a $237.1 million for the same perioddecrease in 2018;oil, gas, and
•
adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2019, was $257.8 million, compared with $256.1 million for the same period in 2018. NGL production revenues and a net derivative loss of $167.2 million, partially offset by a $42.6 million decrease in production expenses and an increase in net gain on extinguishment of debt of $227.3 million. Please refer to the caption Non-GAAP Financial Measures below for our definition of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
Please refer to A Three Month and Nine Month Overview of Selected Production and Financial Information, Including Trends, Comparison of Financial Results and Trends Between the Three Months and NineSix Months Ended SeptemberJune 30, 2020, and 2019 and 2018, and Overview of Liquidity and Capital Resources, below for additional discussion on productionregarding the components of net income (loss) for the periods presented; and production revenues.

•adjusted EBITDAX, a non-GAAP financial measure, for the three months ended June 30, 2020, was $201.5 million, compared with $263.0 million for the same period in 2019. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities.
Operational Activities. The financial results and operational activity discussed throughout this report reflect the impacts of the Pandemic and the misalignment of supply and demand caused by competition among oil producing nations for crude oil market share. We plan to continually monitor the economic environment throughout the year and maintain flexibility to make related financial and operational adjustments as warranted.
In our Midland Basin program, we operated sixfive drilling rigs and threeone completion crewscrew during the thirdsecond quarter of 2019.2020. We drilled 25 gross (23 net) wells and completed 13 gross (10 net) wells during the second quarter of 2020, and increased average net daily production volumes year-over-year by six percent to 76.6 MBOE per day. Costs incurred for oil and gas producing activities in our Midland Basin program during the three months ended June 30, 2020, were $100.8 million, or 75 percent of our total costs incurred for the period. Subsequent to SeptemberJune 30, 2019,2020, we released one completion crewdrilling rig and we expectplan to operate between three and four drilling rigs and between one and two completion crews for the remainder of 2019. For the full year 2019, we expect to average six drilling rigs and three completion crews in the Midland Basin and to allocate approximately 80 percent of our drilling and completion capital to our Midland Basin program.year. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on delineating and developing the Lower and Middle Spraberry and Wolfcamp A and B shale intervals.
28

In our South Texas program, we averagedentered the second quarter with one drilling rig, which we released in June. We drilled four gross (four net) wells and completed one gross (one net) well during the second quarter of 2020. Average net daily production for the second quarter of 2020 was 46.3 MBOE, a 28 percent decrease year-over-year. Costs incurred for oil and gas producing activities in our South Texas program during the three months ended June 30, 2020, were $23.7 million, or 18 percent of our total costs incurred for the period. We anticipate operating one drilling rig and one completion crew at times during the third quarterremainder of 2019. For the full year 2019, we anticipate averaging one to two drilling rigs and one completion crew2020 in South Texas and expect to allocate approximately 20 percent of our drilling and completion capital to this program.Texas. Drilling and completion activities in South Texas continue to focusduring the remainder of 2020 will be focused on developing the Eagle Ford Shale and testing additional intervals and formations, includingdelineating the Austin Chalk Formation. Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to our joint development agreement. All wells subject to this agreement were completed as of September 30, 2019.formation.
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 for the three and ninesix months ended SeptemberJune 30, 2019:2020:
Midland BasinSouth TexasTotal
GrossNetGrossNetGrossNet
Wells drilled but not completed at December 31, 2019Wells drilled but not completed at December 31, 201951  48  21  21  72  69  
Wells drilledWells drilled25  22  3  3  28  25  
Wells completedWells completed(19) (19) (1) (1) (20) (20) 
Other (1)
Other (1)
—  1  —  —  —  1  
Wells drilled but not completed at March 31, 2020Wells drilled but not completed at March 31, 202057  52  23  23  80  75  
Wells drilledWells drilled25  23  4  4  29  27  
Wells completedWells completed(13) (10) (1) (1) (14) (11) 
Wells drilled but not completed at June 30, 2020Wells drilled but not completed at June 30, 202069  65  26  26  95  91  
Midland Basin South Texas Total
Gross Net Gross Net Gross Net
Wells drilled but not completed at December 31, 201861
 55
 29
 23
 90
 78
Wells drilled31
 28
 8
 7
 39
 35
Wells completed(30) (27) (2) (2) (32) (29)
Other (1)
—
 —
 (1) —
 (1) —
Wells drilled but not completed at March 31, 201962
 56
 34
 28
 96
 84
Wells drilled26
 25
 7
 3
 33
 28
Wells completed(36) (32) (11) (11) (47) (43)
Wells drilled but not completed at June 30, 201952

49

30

20
 82
 69
Wells drilled25
 22
 6
 6
 31
 28
Wells completed(21) (19) (17) (6) (38) (25)
Other (1)
—
 —
 —
 (1) —
 (1)
Wells drilled but not completed at September 30, 201956
 52
 19
 19
 75
 71

(1)____________________________________________ Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells.
(1)
Includes adjustments related to normal business activities, including previously drilled wells that we no longer intend to complete and working interest changes for existing drilled but not completed wells.
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 $270.9$134.0 million and $861.4$301.4 million for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, and were incurred in our Midland Basin and South Texas programs.programs as further detailed in Operational Activities above.
Production Results. The table below presents our production by product type for each of our areas of operation for the three months ended SeptemberJune 30, 2019,2020, and 2018:2019:
Midland Basin South Texas TotalMidland BasinSouth TexasTotal
Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30,Three Months Ended June 30,Three Months Ended June 30,Three Months Ended June 30,
2019 2018 2019 2018 2019 2018202020192020201920202019
Production:           Production:
Oil (MMBbl)5.1
 4.8
 0.3
 0.3
 5.4
 5.0
Oil (MMBbl)5.0  5.1  0.4  0.3  5.4  5.4  
Gas (Bcf)9.1
 7.1
 20.4
 20.1
 29.5
 27.2
Gas (Bcf)11.8  8.5  14.2  19.8  26.0  28.3  
NGLs (MMBbl)—
 —
 2.1
 2.4
 2.1
 2.4
NGLs (MMBbl)—  —  1.5  2.3  1.5  2.3  
Equivalent (MMBOE)6.6
 6.0
 5.8
 6.0
 12.4
 12.0
Equivalent (MMBOE)7.0  6.5  4.2  5.9  11.2  12.4  
Avg. daily equivalents (MBOE/d)71.7
 64.8
 63.2
 65.4
 134.9
 130.2
Avg. daily equivalents (MBOE/d)76.6  72.0  46.3  64.6  122.9  136.5  
Relative percentage53% 50% 47% 50% 100% 100%Relative percentage62 %53 %38 %47 %100 %100 %

Note: Amounts may not calculate due to rounding.
29

The table below presents our production by product type for each of our areas of operation for the ninesix months ended SeptemberJune 30, 2019,2020, and 2018:2019:
Midland Basin South Texas 
Rocky Mountain (1)
 TotalMidland BasinSouth TexasTotal
Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30,Six Months Ended June 30,Six Months Ended June 30,Six Months Ended June 30,
2019 2018 2019 2018 2019 2018 2019 2018202020192020201920202019
Production:               Production:
Oil (MMBbl)14.8
 11.8
 0.9
 1.0
 —
 0.9
 15.7
 13.7
Oil (MMBbl)10.9  9.7  0.8  0.6  11.7  10.3  
Gas (Bcf)24.4
 18.9
 57.3
 57.6
 —
 1.2
 81.7
 77.7
Gas (Bcf)21.7  15.4  30.8  36.8  52.5  52.2  
NGLs (MMBbl)—
 —
 6.2
 5.9
 —
 —
 6.2
 6.0
NGLs (MMBbl)—  —  3.1  4.2  3.1  4.2  
Equivalent (MMBOE)18.8
 15.0
 16.7
 16.5
 —
 1.1
 35.5
 32.6
Equivalent (MMBOE)14.6  12.2  9.0  10.9  23.6  23.1  
Avg. daily equivalents (MBOE/d)69.0
 54.9
 61.1
 60.4
 —
 4.1
 130.1
 119.4
Avg. daily equivalents (MBOE/d)80.0  67.6  49.4  60.0  129.4  127.7  
Relative percentage53% 46% 47% 51% —% 3% 100% 100%Relative percentage62 %53 %38 %47 %100 %100 %

Note: Amounts may not calculate due to rounding.
(1)
We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.
Please refer to A Three Month and NineSix Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months and NineSix Months Ended SeptemberJune 30, 2019,2020, and 20182019 below for discussion on production.
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 realized price for the respective period, before the effects of derivative settlements, unless otherwise indicated. 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, contracted pricing benchmarks, and transportation differentials for these products.
The following table summarizes commodity price data, as well as the effects of derivative settlements, for the thirdsecond and secondfirst quarters of 20192020 as well as the thirdsecond quarter of 2018:2019:
For the Three Months EndedFor the Three Months Ended
September 30, 2019 June 30, 2019 September 30, 2018June 30, 2020March 31, 2020June 30, 2019
Oil (per Bbl):     Oil (per Bbl):
Average NYMEX contract monthly price$56.45
 $59.81
 $69.50
Average NYMEX contract monthly price$27.85  $46.17  $59.81  
Realized price, before the effect of derivative settlements$53.99
 $56.04
 $56.96
Realized price, before the effect of derivative settlements$22.25  $45.96  $56.04  
Effect of oil derivative settlements$(0.41) $(1.97) $(3.32)Effect of oil derivative settlements$25.81  $8.44  $(1.97) 
Gas:     Gas:
Average NYMEX monthly settle price (per MMBtu)$2.23
 $2.64
 $2.90
Average NYMEX monthly settle price (per MMBtu)$1.72  $1.95  $2.64  
Realized price, before the effect of derivative settlements (per Mcf)$2.17
 $2.31
 $3.56
Realized price, before the effect of derivative settlements (per Mcf)$1.34  $1.54  $2.31  
Effect of gas derivative settlements (per Mcf)$0.41
 $0.20
 $(0.03)Effect of gas derivative settlements (per Mcf)$0.04  $0.55  $0.20  
NGLs (per Bbl):     NGLs (per Bbl):
Average OPIS price (1)
$18.89
 $22.23
 $37.97
Average OPIS price (1)
$14.02  $17.02  $22.23  
Realized price, before the effect of derivative settlements$15.73
 $16.42
 $30.77
Realized price, before the effect of derivative settlements$10.43  $13.62  $16.42  
Effect of NGL derivative settlements$7.14
 $4.00
 $(9.61)Effect of NGL derivative settlements$1.94  $3.27  $4.00  

(1) ____________________________________________Average OPIS price per barrel of 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.
(1)
Average OPIS price per barrel of 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.
We expect futureDuring the first half of 2020, benchmark prices for oil were impacted by the misalignment of supply and NGLs to remain volatile.demand caused by the Pandemic and competition among oil producing nations for crude oil market share. In addition to supply and demand fundamentals, as a global commodity, the price of oil is 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. NGL prices have trended down as an abundance of NGL volumes from increased drilling in liquid-rich areas have over-supplied today’s market. New demand from petrochemical markets and exports have helped to balance the NGL supply.
We expect gas prices to remain near current levels in the near term due to the abundance of supply relative to demand. Demand from increased liquefied natural gas (“LNG”) exports and gas exports to Mexico are expected to help alleviate oversupply.
Please refer to A Three Month and Nine Month Overview of Selected Production and Financial Information, Including Trends below for additional discussion on our realizedfuture benchmark prices for oil, gas, and NGLs.NGLs to remain depressed for the foreseeable future due to the Pandemic and the misalignment of supply and demand. Our realized prices at
30

local sales points may also be affected by infrastructure capacity in the area of our operations and beyond. Please refer to Second Quarter 2020 Overview and Outlook for the Remainder of 2020 above for additional discussion of factors impacting pricing.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (assuming the same composite NGL barrel(same product mix as discussed under the table above) as of October 24, 2019,July 23, 2020, and SeptemberJune 30, 2019:
2020:
As of October 24, 2019 As of September 30, 2019As of July 23, 2020As of June 30, 2020
NYMEX WTI oil (per Bbl)$55.10
 $52.66
NYMEX WTI oil (per Bbl)$41.74  $39.73  
NYMEX Henry Hub gas (per MMBtu)$2.37
 $2.41
NYMEX Henry Hub gas (per MMBtu)$2.42  $2.32  
OPIS NGLs (per Bbl)$19.70
 $18.89
OPIS NGLs (per Bbl)$19.03  $17.27  
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.derivatives, and decisions regarding entering into derivative commodity contracts are overseen by a financial risk management committee consisting of senior executive officers and finance personnel. The amount of our production covered by derivative instrumentsderivatives is driven by the amount of debt on our balance sheet, the magnitudelevel of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity derivative contracts. With our current derivative commodity contracts, we believe we have partially reduced our exposure to volatility in commodity prices and locationbasis 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 and gas production.
Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
31

Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the quarterthree months ended SeptemberJune 30, 2019,2020, and the immediately preceding three quarters. A detailed discussion follows.
For the Three Months EndedFor the Three Months Ended
September 30, June 30, March 31, December 31,June 30,March 31,December 31,September 30,
2019 2019 2019 20182020202020192019
(in millions)(in millions)
Production (MMBOE)12.4
 12.4
 10.7
 11.3
Production (MMBOE)11.2  12.4  12.8  12.4  
Oil, gas, and NGL production revenue$389.4
 $406.9
 $340.5
 $392.5
Oil, gas, and NGL production revenue$169.8  $354.2  $449.0  $389.4  
Oil, gas, and NGL production expense$129.0
 $123.1
 $121.3
 $121.5
Oil, gas, and NGL production expense$80.4  $119.6  $127.3  $129.0  
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$211.1
 $206.3
 $177.7
 $182.0
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$180.9  $233.5  $228.7  $211.1  
Exploration$11.6
 $10.9
 $11.3
 $14.3
Exploration$9.8  $11.3  $17.7  $11.6  
General and administrative$32.6
 $30.9
 $32.1
 $30.4
General and administrative$27.2  $27.4  $37.2  $32.6  
Net income (loss)$42.2
 $50.4
 $(177.6) $309.7
Net income (loss)$(89.3) $(411.9) $(102.1) $42.2  

Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
For the Three Months Ended
June 30,March 31,December 31,September 30,
2020202020192019
Average net daily production equivalent (MBOE per day)122.9  135.9  138.8  134.9  
Lease operating expense (per BOE)$3.30  $4.75  $4.67  $4.73  
Transportation costs (per BOE)$3.12  $3.11  $3.46  $4.00  
Production taxes as a percent of oil, gas, and NGL production revenue3.7 %4.2 %4.2 %4.1 %
Ad valorem tax expense (per BOE)$0.22  $0.60  $0.37  $0.39  
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)$16.17  $18.88  $17.91  $17.02  
General and administrative (per BOE)$2.43  $2.22  $2.92  $2.63  

Note: Amounts may not calculate due to rounding.
32

 For the Three Months Ended
 September 30, June 30, March 31, December 31,
 2019 2019 2019 2018
Average net daily production equivalent (MBOE per day)134.9
 136.5
 118.7
 122.8
Lease operating expense (per BOE)$4.73
 $4.16
 $5.20
 $4.98
Transportation costs (per BOE)$4.00
 $4.00
 $4.08
 $4.19
Production taxes as a percent of oil, gas, and NGL production revenue4.1% 4.0% 4.1% 3.4%
Ad valorem tax expense (per BOE)$0.39
 $0.44
 $0.76
 $0.39
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)$17.02
 $16.61
 $16.63
 $16.10
General and administrative (per BOE)$2.63
 $2.49
 $3.00
 $2.69

A Three Month and NineSix Month Overview of Selected Production and Financial Information, Including Trends
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 PeriodsFor the Three Months Ended June 30,Amount Change Between PeriodsPercent Change Between PeriodsFor the Six Months Ended June 30,Amount Change Between PeriodsPercent Change Between Periods
2019 2018 2019 2018 2020201920202019
Net production volumes: (1)
               
Net production volumes: (1)
Oil (MMBbl)5.4
 5.0
 0.4
 7 % 15.7
 13.7
 2.0
 15 %Oil (MMBbl)5.4  5.4  (0.1) (1)%11.7  10.3  1.5  14 %
Gas (Bcf)29.5
 27.2
 2.3
 9 % 81.7
 77.7
 4.0
 5 %Gas (Bcf)26.0  28.3  (2.3) (8)%52.5  52.2  0.3  1 %
NGLs (MMBbl)2.1
 2.4
 (0.3) (14)% 6.2
 6.0
 0.2
 4 %NGLs (MMBbl)1.5  2.3  (0.8) (35)%3.1  4.2  (1.1) (26)%
Equivalent (MMBOE)12.4
 12.0
 0.4
 4 % 35.5
 32.6
 2.9
 9 %Equivalent (MMBOE)11.2  12.4  (1.2) (10)%23.6  23.1  0.4  2 %
Average net daily production: (1)
               
Average net daily production: (1)
Oil (MBbl per day)59.0
 54.9
 4.1
 7 % 57.5
 50.1
 7.4
 15 %Oil (MBbl per day)59.0  59.6  (0.6) (1)%64.4  56.7  7.7  14 %
Gas (MMcf per day)320.6
 295.3
 25.3
 9 % 299.2
 284.7
 14.5
 5 %Gas (MMcf per day)285.8  310.9  (25.1) (8)%288.5  288.3  0.2  — %
NGLs (MBbl per day)22.5
 26.2
 (3.7) (14)% 22.8
 21.9
 0.9
 4 %NGLs (MBbl per day)16.2  25.1  (8.8) (35)%16.9  23.0  (6.0) (26)%
Equivalent (MBOE per day)134.9
 130.2
 4.6
 4 % 130.1
 119.4
 10.7
 9 %Equivalent (MBOE per day)122.9  136.5  (13.6) (10)%129.4  127.7  1.7  1 %
Oil, gas, and NGL production revenue (in millions): (1)
               
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue$292.9
 $287.5
 $5.3
 2 % $836.1
 $814.7
 $21.3
 3 %Oil production revenue$119.5  $304.1  $(184.6) (61)%$411.2  $543.2  $(132.0) (24)%
Gas production revenue64.0
 96.8
 (32.8) (34)% 194.4
 260.0
 (65.6) (25)%Gas production revenue34.9  65.2  (30.4) (47)%75.6  130.3  (54.8) (42)%
NGL production revenue32.5
 74.1
 (41.5) (56)% 106.3
 169.1
 (62.8) (37)%NGL production revenue15.4  37.5  (22.1) (59)%37.2  73.8  (36.5) (50)%
Total oil, gas, and NGL production revenue$389.4
 $458.4
 $(69.0) (15)% $1,136.7
 $1,243.8
 $(107.1) (9)%Total oil, gas, and NGL production revenue$169.8  $406.9  $(237.1) (58)%$524.0  $747.3  $(223.3) (30)%
Oil, gas, and NGL production expense (in millions): (1)
               
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense$58.7
 $52.8
 $5.8
 11 % $166.0
 $151.9
 $14.1
 9 %Lease operating expense$36.9  $51.7  $(14.8) (29)%$95.7  $107.3  $(11.6) (11)%
Transportation costs49.6
 50.4
 (0.8) (2)% 142.9
 144.1
 (1.2) (1)%Transportation costs34.9  49.7  (14.9) (30)%73.3  93.3  (20.0) (21)%
Production taxes16.0
 19.0
 (3.0) (16)% 46.1
 53.4
 (7.3) (14)%Production taxes6.2  16.1  (9.9) (61)%21.1  30.1  (9.0) (30)%
Ad valorem tax expense4.8
 5.4
 (0.7) (12)% 18.4
 16.5
 1.9
 11 %Ad valorem tax expense2.4  5.5  (3.1) (56)%9.9  13.6  (3.7) (27)%
Total oil, gas, and NGL production expense$129.0
 $127.6
 $1.4
 1 % $373.4
 $365.9
 $7.5
 2 %Total oil, gas, and NGL production expense$80.4  $123.1  $(42.6) (35)%$200.0  $244.4  $(44.4) (18)%
Realized price (before the effect of derivative settlements):               
Realized price, before the effect of derivative settlements:Realized price, before the effect of derivative settlements:
Oil (per Bbl)$53.99
 $56.96
 $(2.97) (5)% $53.31
 $59.60
 $(6.29) (11)%Oil (per Bbl)$22.25  $56.04  $(33.79) (60)%$35.09  $52.95  $(17.86) (34)%
Gas (per Mcf)$2.17
 $3.56
 $(1.39) (39)% $2.38
 $3.35
 $(0.97) (29)%Gas (per Mcf)$1.34  $2.31  $(0.97) (42)%$1.44  $2.50  $(1.06) (42)%
NGLs (per Bbl)$15.73
 $30.77
 $(15.04) (49)% $17.09
 $28.28
 $(11.19) (40)%NGLs (per Bbl)$10.43  $16.42  $(5.99) (36)%$12.09  $17.76  $(5.67) (32)%
Per BOE$31.39
 $38.26
 $(6.87) (18)% $32.00
 $38.15
 $(6.15) (16)%Per BOE$15.18  $32.75  $(17.57) (54)%$22.25  $32.34  $(10.09) (31)%
Per BOE data:               Per BOE data:
Production costs:               Production costs:
Lease operating expense$4.73
 $4.41
 $0.32
 7 % $4.67
 $4.66
 $0.01
 — %Lease operating expense$3.30  $4.16  $(0.86) (21)%$4.06  $4.64  $(0.58) (13)%
Transportation costs$4.00
 $4.20
 $(0.20) (5)% $4.02
 $4.42
 $(0.40) (9)%Transportation costs$3.12  $4.00  $(0.88) (22)%$3.11  $4.04  $(0.93) (23)%
Production taxes$1.29
 $1.58
 $(0.29) (18)% $1.30
 $1.64
 $(0.34) (21)%Production taxes$0.56  $1.30  $(0.74) (57)%$0.90  $1.30  $(0.40) (31)%
Ad valorem tax expense$0.39
 $0.45
 $(0.06) (13)% $0.52
 $0.51
 $0.01
 2 %Ad valorem tax expense$0.22  $0.44  $(0.22) (50)%$0.42  $0.59  $(0.17) (29)%
Total production costs (1)
Total production costs (1)
$7.20  $9.90  $(2.70) (27)%$8.49  $10.57  $(2.08) (20)%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$17.02
 $16.78
 $0.24
 1 % $16.76
 $14.82
 $1.94
 13 %Depletion, depreciation, amortization, and asset retirement obligation liability accretion$16.17  $16.61  $(0.44) (3)%$17.59  $16.62  $0.97  6 %
General and administrative$2.63
 $2.46
 $0.17
 7 % $2.69
 $2.64
 $0.05
 2 %General and administrative$2.43  $2.49  $(0.06) (2)%$2.32  $2.73  $(0.41) (15)%
Derivative settlement gain (loss) (2)
$1.99
 $(3.40) $5.39
 159 % $0.67
 $(3.13) $3.80
 121 %
Derivative settlement gain (loss) (2)
$12.74  $0.32  $12.42  3,881 %$9.17  $(0.04) $9.21  23,025 %
Earnings per share information:               Earnings per share information:
Basic weighted-average common shares outstanding (in thousands)112,804
 112,107
 697
 1 % 112,441
 111,836
 605
 1 %Basic weighted-average common shares outstanding (in thousands)113,008  112,2627461 %113,015  112,257  758  1 %
Diluted weighted-average common shares outstanding (in thousands)113,334
 112,107
 1,227
 1 % 112,441
 113,600
 (1,159) (1)%Diluted weighted-average common shares outstanding (in thousands)113,008  112,93276— %113,015  112,257  758  1 %
Basic net income (loss) per common share$0.37
 $(1.21) $1.58
 131 % $(0.76) $1.78
 $(2.54) (143)%Basic net income (loss) per common share$(0.79) $0.45  $(1.24) (276)%$(4.43) $(1.13) $(3.30) (292)%
Diluted net income (loss) per common share$0.37
 $(1.21) $1.58
 131 % $(0.76) $1.75
 $(2.51) (143)%Diluted net income (loss) per common share$(0.79) $0.45  $(1.24) (276)%$(4.43) $(1.13) $(3.30) (292)%

(1) ______________________________________Amounts and percentage changes may not calculate due to rounding.
(1)
(2) Derivative settlements for the three and six months ended June 30, 2020, and 2019, are included within the net derivative (gain) loss line item in the accompanying statements of operations.
33

Amount and percentage changes may not calculate due to rounding.
(2)
Derivative settlements for the three and nine months ended September 30, 2019, and 2018, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

Average netdaily equivalent daily production for the three and ninesix months ended SeptemberJune 30, 2019, increased four2020, decreased 10 percent and nineincreased one percent, respectively, compared with the same periods in 2018. These results were primarily driven by the performance of our Midland Basin assets, which had increases in production volumes of 11 percent and 26 percent2019. The decrease for the three and nine months ended SeptemberJune 30, 2019, respectively, compared with the same periods2020, was driven by a 28 percent decrease in 2018. Productionaverage daily equivalent production volumes from our South Texas assets, decreased three percent and increased one percent for the three and nine months ended September 30, 2019, respectively. We divested our remaining producing assets in the Rocky Mountain region in the first half of 2018. On a retained asset basis, production volumes increased 13 percent for the nine months ended September 30, 2019, compared with the same period in 2018.2019. Average daily equivalent production volumes from our Midland Basin assets increased six percent for the three months ended June 30, 2020, compared with the same period in 2019. The overall decrease in average daily equivalent production for the three months ended June 30, 2020, was primarily due to voluntary production curtailments, fewer net well completions during the three months ended June 30, 2020, compared with the same period in 2019, and deferral of production start-up of completed wells until June 2020, all of which were in response to low commodity prices in April and May of 2020. For the six months ended June 30, 2020, increases in average daily equivalent production volumes from our Midland Basin assets were mostly offset by decreases in average daily equivalent production volumes from our South Texas assets. For the full year 2019,2020, we expect total production as well as oil production as a percentage of our total product mix,volumes to increasedecrease compared with 2018, primarily as a result of actual and anticipated production increases in our Midland Basin program. Currently, we expect production volumes from South Texas to remain flat year over year.2019.
Below is a discussion of certain financial results, some of which are presented on a per BOE basis. We present thiscertain information on a per BOE basis because we believe it is an effective wayin order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.
Our realized price before the effect of derivative settlements on a per BOE basis decreased 1854 percent and 1631 percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018. These decreases were2019, primarily driven by lower benchmark commodity prices for oil, gas, and NGLs. In addition to lower commodity prices, regionalNGLs resulting from the Pandemic and other macroeconomic events. Regional pricing differentials in the Midland Basin caused by tight takeaway capacity further affected realized prices. In the first half of 2019, certain third-party midstream force majeure events negatively affected the price we received for our Midland Basin gas production. Regional differentials for gasrealized prices in the Midland Basin are expected to2019 and continue to negatively affect our realized prices into 2020, when additional expected take-away capacity is anticipated to come on-line.in 2020. For the three and ninesix months ended SeptemberJune 30, 2019,2020, we recognized gains of $1.99$12.74 per BOE and $0.67$9.17 per BOE, respectively, on the settlement of our derivative contracts, compared to recognized losses of $3.40 and $3.13 per BOE, forcontracts. For the three and ninesix months ended SeptemberJune 30, 2018, respectively.2019, we recognized a gain of $0.32 per BOE and a loss of $0.04 per BOE, respectively, on the settlement of our derivative contracts.
Lease operating expense (“LOE”) on a per BOE basis increased sevendecreased 21 percent and 13 percent for the three and six months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periodperiods in 2018. This increase was primarily2019. These decreases were driven by increased LOEour efforts to reduce costs, and reduced workover expense on our South Texas assets. Foractivity in the nine months ended September 30, 2019, LOE on a per BOE basis was flat compared with the same period in 2018.first half of 2020. For the full year 2020, we expect LOE on a per BOE basis to be flat in 2019lower compared with 2018. We may experience2019 as we continue to benefit from reduced costs and improved operational efficiencies. While we will continue our efforts to reduce costs during 2020, we anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and changes in industry activity, and the effects such changes could have on service provider costs.all of which impacts total LOE expense.
Transportation costs on a per BOE basis decreased five22 percent and nine23 percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018.2019. These decreases were driven primarily by an increasea 28 percent and 18 percent reduction in average daily equivalent production volumes from our South Texas assets, which incur the percentagemajority of our transportation costs, for the three and six months ended June 30, 2020, respectively, compared with the same periods in 2019. These decreases were partially offset by increased average daily equivalent production volumes generated from our Midland Basin assets, as production from these assets is typically sold at or near the wellhead and incurs minimal transportation costs. We expect total transportation costs to fluctuate relative to changes in production from our South Texas assets, which incur the majority of our transportation costs.assets. On a per BOE basis, we expect transportation costs to decrease in 2019,2020, compared with 2018,2019, as production from our Midland Basin assets continues to become a larger portion of our total production.production and as production from our South Texas assets continues to decline.
Production taxes on a per BOE basis decreased 1857 percent and 2131 percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018.2019. These decreases were primarily driven by the 18 percent and 16 percent decreasesa decrease in realized price on a per BOE basis before the effects of derivative settlementsprices. Our overall production tax rates for the three and ninesix months ended SeptemberJune 30, 2019,2020, were 3.7 percent and 4.0 percent, respectively, compared with the same periods in 2018. Our overall production tax rateto 4.0 percent for each of the three and ninesix months ended SeptemberJune 30, 2019, was 4.1 percent compared2019. We expect our total production tax expense to 4.1 percent and 4.3 percent for the three and nine months ended September 30, 2018, respectively. The decrease in our2020, compared with 2019, as we expect oil, gas, and NGL production tax rate for the nine months ended September 30, 2018 was primarily the result of divesting our producing assets in the Rocky Mountain region, which were subjectrevenue to higher tax rates than our properties in Texas.decrease due to decreased volumes and pricing. We generally expect production tax expense to trend 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 we recognize.
Ad valorem tax expense on a per BOE basis decreased 1350 percent and 29 percent for the three and six months ended SeptemberJune 30, 2020, respectively, compared with the same periods in 2019, comparedresulting from changes to the same period2020 anticipated value assessments of our producing properties by respective tax authorities. We anticipate volatility in 2018. For the nine months ended September 30, 2019, ad valorem tax expense per BOE was relatively flat compared with the same period in 2018 as the expected increases on an absolute basis were consistent with higher production volumes. We expect our full-year 2019 ad valorem tax expense to remain consistent with 2018 on a per BOE and absolute basis as increases on an absolute basis continue to trend in line with higher production volumes.the valuation of our producing properties change.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased onedecreased three percent and 13increased six percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018. These increases were2019. The decrease for the three months ended June 30, 2020, was driven by the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020, partially offset by higher production volumes from our oil producing Midland Basin assets as these assets have higher depletion rates than our primarily gas and NGL producing South Texas assets. The increase for the six months ended June 30, 2020, was primarily driven by our focus on developing oil producing assets in the Midland Basin, which have higher depletion rates than our primarily gas and NGL producing assets in South Texas.Basin. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. In general, we expectOur assets in the Midland Basin have higher DD&A expense on a per BOE basisrates than our assets in 2019 to increase compared with 2018 asSouth Texas, and while the percentage of our total production mix from the Midland Basin continues to increase, we expect that the impairment we recorded in the first quarter of 2020 for our South Texas assets combined with an overall decrease in capital
34

development costs in 2020 will result in a full year DD&A rate that is relatively flat compared with 2019. Although we expect DD&A per BOE to be comparable with the prior year, we expect DD&A expense on an absolute basis for the full year 2020 to be lower compared with the year ended December 31, 2019, as a percentageresult of our total production.

anticipated decreased production volumes.
General and administrative (“G&A”) expense on a per BOE basis increased sevendecreased two percent and two15 percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018. These increases are2019. The decrease for the six months ended June 30, 2020, was primarily due to less employee compensation being reclassified to exploration expense as more employee time is being allocated to development activities. As we expect a continued high focusreduced overhead costs resulting from the reorganization of capital allocation to the Midland Basin, we reorganized certain functions duringin the fourth quarter of 2019 to eliminatethat eliminated duplicative regional operationoperational functions and reduce overhead costs, which we expect will result in reduced G&A expense in future years. As a result, we expect to incur total charges related to this reorganization ranging from $7.0 million to $8.5 million, including a range of $3.0 million to $5.0 million to be incurred in the fourth quarter of 2019. Therefore,Pandemic. For the full year 2020, we expect G&A expense for the full-year 2019 to increasedecrease, in total and on a per BOE basis, compared with 2018.2019.
Please refer to Comparison of Financial Results and Trends Between the Three Months and NineSix Months Ended SeptemberJune 30, 2019,2020, and 20182019 below for additional discussion on operating expenses.
Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for discussion of our basic and diluted net income (loss) per common share calculations.
Comparison of Financial Results and Trends Between the Three Months and NineSix Months Ended SeptemberJune 30, 2019,2020, and 20182019
Net equivalent production, production revenue, and production expense
The following table presents the regional changes in our net equivalent production, production revenue, and production expense between the three and six months ended SeptemberJune 30, 2019,2020, and 2018:2019:
Net Equivalent Production
Increase (Decrease)		Production Revenue
Decrease		Production Expense
Decrease
Net Equivalent Production
Increase (Decrease)		 Production Revenue
Decrease		 Production Expense
Increase (Decrease)		Three Months EndedSix Months EndedThree Months EndedSix Months EndedThree Months EndedSix Months Ended
(MBOE per day) (in millions) (in millions)(MBOE per day)(in millions)(in millions)
Midland Basin6.9
 $(15.7) $1.8
Midland Basin4.6  12.3  $(178.5) $(131.9) $(18.0) $(10.5) 
South Texas(2.3) (53.2) (0.4)South Texas(18.2) (10.6) (58.5) (91.4) (24.6) (33.9) 
Total4.6
 $(69.0) $1.4
Total(13.6) 1.7  $(237.1) $(223.3) $(42.6) $(44.4) 
__________________________________________

Note: Amounts may not calculate due to rounding.
The following table presents the regional changesWe experienced a 10 percent decrease in our net equivalent daily production for the three months ended June 30, 2020, compared with the same period in 2019, primarily as a result of decreased production from our South Texas assets. The decrease was primarily due to voluntary production curtailments, fewer net well completions during the three months ended June 30, 2020, compared with the same period in 2019, and deferral of production start-up of completed wells until June 2020, all of which were in response to low commodity prices in April and May of 2020. Net equivalent daily production remained relatively flat for the six months ended June 30, 2020, compared with the same period in 2019. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased 60 percent, 42 percent, and 36 percent, respectively, for the three months ended June 30, 2020, compared with the same period in 2019. For the six months ended June 30, 2020, realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased 34 percent, 42 percent, and 32 percent, respectively, compared with the same period in 2019. As a result of the decreases in production and pricing, oil, gas, and NGL production revenue and production expense between the nine months ended September 30, 2019, and 2018:
 Net Equivalent Production
Increase (Decrease)		 Production Revenue
Increase (Decrease)		 Production Expense
Increase (Decrease)
 (MBOE per day) (in millions) (in millions)
Midland Basin14.1
 $39.7
 $24.3
South Texas0.7
 (89.5) 6.5
Rocky Mountain (1)
(4.1) (57.2) (23.3)
Total10.7
 $(107.1) $7.5
__________________________________________
Note: Amounts may not calculate due to rounding.
(1)
We divested our remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.
As previously discussed, production on a net equivalent basis increased fourdecreased 58 percent and nine30 percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018, as a result of increased production, primarily from our Midland Basin assets. Oil, gas, and NGL production revenues decreased 15 percent for the three months ended September 30, 2019, compared with the same period in 2018, primarily as a result of decreases in commodity prices. Oil, gas, and NGL production revenues decreased nine percent for the nine months ended September 30, 2019, compared with the same period in 2018, as a result of weaker commodity pricing and the divestiture in the first half of 2018 of our remaining producing assets in the Rocky Mountain region. On a retained asset basis, production volumes increased 13 percent for the nine months ended September 30, 2019, compared with the same period in 2018. 2019.
Total production expense for the three and ninesix months ended SeptemberJune 30, 2019, compared with the same periods in 2018, was relatively flat as increased lease operating expense was offset by2020, decreased production taxes and transportation costs. Production expense on a per BOE basis decreased two35 percent and six18 percent, for the three and nine months ended September 30, 2019, respectively, compared with the same periods in 2018, primarily due to increased production volumes, decreased transportation costs on a per BOE basis, and decreased production taxes driven by lower oil, gas, and NGL production revenues.2019. Please refer to A Three Month and NineSix Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including trends on a per BOE basis.

Net gain on divestiture activity
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions)
Net gain on divestiture activity$—
 $0.8
 $0.3
 $425.7
The $425.7 million net gain on divestiture activity recorded for the nine months ended September 30, 2018, was primarily the result of an estimated net gain of $410.6 million recorded for the PRB Divestiture, which closed in the first quarter of 2018. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions in Part I, Item 1 of this report for additional discussion.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$211.1
 $201.1
 $595.2
 $483.3
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$180.9  $206.3  $414.3  $384.1  
DD&A expense increased fivedecreased 12 percent and 23increased eight percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018.2019. The increases directly relatedecrease for the three months ended June 30, 2020 was related to the 11reduction in the depletable cost basis of our South Texas proved oil and gas properties, resulting from proved property impairments during the first quarter of 2020. This decrease was partially offset by a six percent and 26 percent increasesincrease in average daily equivalent production
35

volumes from our Midland Basin assets for the three and nine months ended September 30, 2019, respectively, as these assets have higher depletion rates than our assets in South Texas. The increase for the six months ended June 30, 2020, was driven by an 18 percent increase in average daily equivalent production volumes from our Midland Basin assets.
Exploration
For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,		For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2019 2018 2019 20182020201920202019
(in millions)(in millions)
Geological and geophysical expenses$1.1
 $0.6
 $2.0
 $4.5
Geological and geophysical expenses$0.2  $0.4  $1.4  $0.8  
Overhead and other expenses10.5
 12.5
 31.9
 36.3
Overhead and other expenses9.6  10.5  19.7  21.4  
Total exploration$11.6
 $13.1
 $33.9
 $40.8
TotalTotal$9.8  $10.9  $21.1  $22.2  
Exploration expense decreased 1110 percent and 17five percent for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periods in 2018. The2019. These decreases were primarily driven by a reductionthe reorganization of certain functions in the amountfourth quarter of employee compensation reclassified to exploration expense as more employee time is being allocated to development activities, which is recognized as G&A expense. Additionally, spending on geological2019 that eliminated duplicative regional operational functions and geophysical activities decreased forreduced overhead costs. For the nine months ended September 30, 2019, compared with the same period in 2018. In 2019,full year 2020, we expect total exploration expense to be slightly lowerdecrease compared with 2018;2019 as a result of lower overhead; however, our expectations could change depending onexploration expense is impacted by actual geological and geophysical studies performedwe perform and the potential for exploratory dry hole expense.
Impairment
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions)
Impairment of proved oil and gas properties and related support equipment$—  $—  $956.7  $—  
Abandonment and impairment of unproved properties8.8  12.4  41.9  18.8  
Total$8.8  $12.4  $998.5  $18.8  

Note: Amounts may not calculate due to rounding.
As a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices, we recorded impairment expense related to our South Texas proved propertiesoil and Abandonmentgas properties and impairment of unproved properties
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions)
Abandonment and impairment of unproved properties$6.3
 $9.1
 $25.1
 $26.6

related support facilities during the six months ended June 30, 2020. There were no proved oil and gas property impairments forrecorded during the same period in 2019. Unproved property abandonments and impairments recorded during the three and ninesix months ended SeptemberJune 30, 20192020, and 2018. Unproved property abandonment and impairment expense recorded for the three and nine months ended September 30, 2019 and 2018 related to actual and anticipated lease expirations, as well as actual and anticipated losses onof acreage due to title defects, changes in development plans, and other inherent acreage risks.
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 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.
FutureReserve estimates and related impairments of proved and unproved properties are difficult to predict; however, basedpredict in a volatile price environment. If commodity prices for the products we produce remain depressed or decline further as a result of demand fundamentals associated with the Pandemic or competition among oil producing nations for crude oil market share, we may experience additional proved and unproved property impairments in the future. Given the uncertainties in commodity prices and the associated impacts they may have on our commodity price assumptionsservice provider costs, we cannot predict with any reasonable certainty the likelihood or magnitude of further property impairments beyond those recorded during the six months ended June 30, 2020.
Please refer to Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion of impairment expense.
36

General and administrative
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions)
General and administrative$27.2  $30.9  $54.7  $63.0  
G&A expense decreased 12 percent and 13 percent for the three and six months ended June 30, 2020, respectively, compared with the same periods in 2019. These decreases were primarily due to reduced overhead costs as a result of October 24, 2019, we do not expect any material property impairmentsthe reorganization that was announced in the fourth quarter of 2019 resulting from commodity price impacts.
General and administrative
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions)
General and administrative$32.6
 $29.5
 $95.6
 $86.1

G&A expense increased 11 percent for each of the three and nine months ended September 30, 2019, compared with the same periods in 2018.Pandemic. Please refer to the section A Three Month and NineSix Month Overview of Selected Production and Financial Information, Including Trends above for furtheradditional discussion of G&A expense in total and on a per BOE basis.
Net derivative (gain) loss
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions)
Net derivative (gain) loss$(100.9) $178.0
 $(3.5) $249.3
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions)
Net derivative (gain) loss$167.2  $(79.7) $(378.1) $97.4  
We recognized a $545.3 million derivative gain in the first quarter of 2020 and a loss of $167.2 million in the second quarter of 2020. The gain in the first quarter of 2020 was primarily driven by a $471.9 million upward mark-to-market adjustment due to weakening oil prices during the first three months of the year. For the six months ended June 30, 2020, the derivative gain in the first quarter was partially offset by a derivative loss of $167.2 million as a result of a $309.7 million downward mark-to-market adjustment due to strengthening oil prices during the three months ended June 30, 2020. Additionally, we recognized gains on the settlement of derivative contracts of $142.5 million and $216.0 million during the three and six months ended June 30, 2020, respectively.
We recognized a $177.1 million derivative loss in the first quarter of 2019 and derivative gainsa gain of $79.7 million and $100.9 million in the second and third quartersquarter of 2019, respectively.2019. The loss in the first quarter of 2019 was primarily driven by a $172.1 million downward mark-to-market adjustment due to strengthening oil prices during the first three months of the year. TheFor the six months ended June 30, 2019, the derivative gainsloss recognized in the second and third quarters were primarily drivenfirst quarter was partially offset by increases in the fair valuea derivative gain of derivative contracts settling subsequent to June 30, 2019, and September 30, 2019, of $75.6$79.7 million, and $76.2 million, respectively, as a result of a $75.6 million upward mark-to-market adjustment due to weakening commodity prices during these periods.the three months ended June 30, 2019. In addition, there waswe recognized a $23.8$5.0 million loss and a $4.1 million gain on derivative contracts that settled during the nine months ended September 30, 2019.
We recognized a $178.0 million derivative loss for the three months ended September 30, 2018, due in part to a $186.0 million decrease in the fair value of contracts settling subsequent to September 30, 2018. Additionally, we recognized an $8.0 million gain on contracts that settled during the third quarter of 2018, which had a fair value of $48.7 million at June 30, 2018, and settled for a loss of $40.7 million. We recognized a $7.6 million loss on first and second quarter 2018 contract settlements and recorded a $63.7 million decrease to the fair valuequarters of remaining contracts as of June 30, 2018, resulting in a year-to-date net derivative loss of $249.3 million for the nine months ended September 30, 2018.2019, respectively.
Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information.discussion.
Interest expense
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions)
Interest expense$40.4  $39.6  $81.9  $77.6  
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions)
Interest expense$40.6
 $38.1
 $118.2
 $122.9
Interest expense increased sixtwo percent and five percent for the three and six months ended SeptemberJune 30, 2019,2020, respectively, compared with the same periodperiods in 2018 as2019. The increase for the six months ended June 30, 2020, was a result of increasedan increase in interest expense associated with borrowings against our revolving credit facility in 2019. Our credit facility remained undrawn throughout 2018.

Interest expense decreased four percent for the nine months ended September 30, 2019, compared with the same period in 2018. This decrease was driven primarily by the redemption of our 2021 Senior Notes in the third quarter of 2018, which reduced interest expense related to debt during the nine months ended September 30, 2019 by $12.1 million compared with the same period in 2018. This decrease was2020, partially offset by increaseda decrease in interest expense associated with borrowings against our credit facility in 2019 whereas no borrowings were made against our credit facility in 2018.capitalized to wells. We expect interest expense related to our Senior Notes to remain relatively flat for the remainder of 20192020 compared with 2018; however, total2019. Our expectation for interest expense for the remainder of 2020 remains unchanged as the increase related to the higher interest rate on the issuance of the 2025 Senior Secured Notes will be mostly offset by the decreased interest associated with the reduction in principal of Old Notes exchanged. Total interest expense is impacted by and can vary based on the timing and amount of borrowings against our revolving credit facility throughout the remainderfacility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of 2019.this report and Overview of Liquidity and Capital Resources below for additional discussion.
Loss
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Gain on extinguishment of debt
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions)
Loss on extinguishment of debt$—
 $26.7
 $—
 $26.7
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions)
Gain on extinguishment of debt$227.3  $—  $239.5  $—  
ForThe Exchange Offers executed during the second quarter of 2020 resulted in a net gain on extinguishment of debt of $227.3 million, which was primarily comprised of the partial principal redemption of Old Notes and the debt discount associated with the issuance of the 2025 Senior Secured Notes. During the three and nine months ended September 30, 2018,March 31, 2020, we recorded a $26.7$12.2 million net lossgain on the early extinguishment of our 2021 Senior Notes, 2023 Senior Notes, and a portion of our 2022 Senior Notes, which included $20.4discounts realized upon repurchase of $12.4 million associated with the premiums paid upon redemption and repurchase, and $6.3 million related to the accelerationpartially offset by approximately $235,000 of accelerated unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional information.
Please refer to Note 5 - Long-Term Debt in Part I, Item I of this report and Overview of Liquidity and Capital Resourcesbelow for additional information.discussion on these transactions.
Income tax (expense) benefit
For the Three Months Ended
June 30,		For the Six Months Ended
June 30,
2020201920202019
(in millions, except tax rate)
Income tax (expense) benefit$36.7  $(13.6) $135.7  $32.4  
Effective tax rate29.1 %21.2 %21.3 %20.3 %
 For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,
 2019 2018 2019 2018
 (in millions, except tax rate)
Income tax (expense) benefit$(16.1) $36.7
 $16.3
 $(61.3)
Effective tax rate27.6% 21.3% 16.1% 23.6%
The increase in the effectiveincome tax benefit rate for the three months ended SeptemberJune 30, 2020, compared to the income tax expense rate during the same period in 2019, was primarily due to the release of a valuation allowance on deferred tax assets during the second quarter of 2020, which increased the tax benefit rate. The increase in effective tax rate for the six months ended June 30, 2020, compared with the same period in 2018, was primarily due to the differing2019, reflects proportional income tax effects offrom differences between forecasted income or loss, estimated state permanent items on income before income taxes for the three months ended September 30, 2019, compared to their impact on the loss before income taxes for the same period in 2018.
The decrease in the effective tax rate for the nine months ended September 30, 2019, compared with the same period in 2018, was primarily due to the differing effects of permanent items on the loss before income taxes for the nine months ended September 30, 2019, compared to their impact on income before income taxes for the same period in 2018.
Discrete expenses related todifferences, excess tax deficiencies from stock-based compensation awards, and limits toon expensing of certain covered individual’s compensation, and other permanent expense items reduced the tax benefit rate for the nine months ended September 30, 2019, and the three months ended September 30, 2018. These same items increased the tax expense rate for the three months ended September 30, 2019, and the nine months ended September 30, 2018. The reduction in the tax expense rate also reflects a cumulative effect in 2018 from divestitures, and the impact of a correlative change to our state apportionment rate.
individuals’ compensation. Please refer toOverview of Liquidity and Capital Resources below as well as 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, we believe we have sufficient liquidity and capital resources to executeachieve our business plan for the foreseeable future.operational objectives, while continuing to meet our current financial obligations in a challenging commodity price environment. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.expenditures, and we have successfully renegotiated certain contracts and have realized cost savings that directly support our objective of maximizing cash flows.
Sources of Cash
We currently expect our 20192020 capital program to be funded by cash flows from operations with any remaining cash that was on hand as of December 31, 2018, andneeds being funded by borrowings under our revolving credit facility. During the ninesix months ended SeptemberJune 30, 2019,2020, we generated

$581.6 $332.5 million of cash flows from operating activities. As of September 30, 2019, the remaining available borrowing capacity under our Credit Agreement provided $1.1 billion in liquidity.
Although we expect cash flows from these sources to be sufficient to fund our expected 20192020 capital program, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. Further, we may enter into additional carrying cost funding and sharing arrangements with third parties for certain exploration or development programs. Our borrowing base could be reduced as a result of lower commodity prices, divestitures of properties with proved reserves, or the issuance of additional debt securities. 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-issued securities may have rights, preferences, or privileges senior to those of existing stockholders. 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 affected by the general conditions of the broader economy, force majeure events, and fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry.
As a result of the current macroeconomic environment, our credit ratings were downgraded during the first half of 2020 by three major rating agencies. These downgrades and any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. 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. Current or future macroeconomic events may negatively impact our ability to capitalize on these contracts. Please refer to Note 10 - Derivative Financial Instruments in 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.
The enactment of the Tax Cuts and Jobs Act (the “2017 Tax Act”) reduced our highest marginal corporate tax rate for 2018 and future years from 35 percent to 21 percent, however future deductibility of interest expense may be limited. In general, the enactment of the 2017 Tax Act has had a positive impact on operating cash flows, and we believe it will positively impact future operating cash flows.
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Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion and is scheduled to mature on September 28, 2023. The maturity date could, however, occur earlier on August 16, 2022, if we have not completed certain repurchase, redemption, or refinancing activities associated with our 2022 Senior Notes, as outlined in the Credit Agreement. The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each as determined by our lender group. The next scheduledDuring the second quarter of 2020, we completed the semi-annual borrowing base redetermination with our lenders, and entered into the Amendments, as defined in Note 5 - Long-Term Debt in Part I, Item 1 of this report. As a result of lower commodity prices and a corresponding decrease in the value of our proved reserves, the borrowing base and aggregate lender commitments were both reduced to $1.1 billion. The Amendments allowed for Permitted Second Lien Debt of up to $1.0 billion, inclusive of the 2021 Senior Convertible Notes, provided that all principal amounts of such debt are used to redeem unsecured senior debt of the Company for less than or equal to 80% of par value. As of June 30, 2020, the Company has $487.8 million of available Permitted Second Lien Debt capacity available to be used prior to the next scheduled redetermination date is Aprilof October 1, 2020.
Our daily weighted-average credit facility debt balance was approximately $170.9 As of June 30, 2020, the remaining available borrowing capacity under our Credit Agreement provided $865.0 million and $97.5 million for the three and nine months ended September 30, 2019. Our credit facility remained undrawn throughout 2018. Cash flows provided byin liquidity; however, our operating activities, proceeds received fromborrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, capital markets activities,or financing activities. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and our capital expenditures all impact the amount we borrowavailable borrowing capacity under our credit facility.Credit Agreement as of July 23, 2020, June 30, 2020, and December 31, 2019.
We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as defined byset forth in the Credit Agreement. The financial covenants under the Credit Agreement require that our (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which will use annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ended December 31, 2018 through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00;1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. We were in compliance with all financial and non-financial covenants as of SeptemberJune 30, 2019,2020, and through the filing of this report. Please refer to the caption Non-GAAP Financial Measures below for our definition of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
Our daily weighted-average revolving credit facility debt balance was $121.9 million and $107.6 million for the three months ended June 30, 2020, and 2019, respectively, and $113.0 million and $60.1 million for the six months ended June 30, 2020, and 2019, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.
Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Our Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. We currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business. Please refer to Note 1 - Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04 which provides guidance related to reference rate reform.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and the non-cash amortization of the discountdiscounts related to the 2025 Senior Secured Notes and 2021 Senior Secured Convertible Notes. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the three and ninesix months ended SeptemberJune 30, 2019,2020, and 2018:
2019:
For the Three Months Ended
September 30,		 For the Nine Months Ended
September 30,		For the Three Months Ended
June 30,		For the Six Months Ended June 30,
2019 2018 2019 20182020201920202019
Weighted-average interest rate6.3% 6.4% 6.4% 6.4%Weighted-average interest rate6.7 %6.5 %6.6 %6.5 %
Weighted-average borrowing rate5.6% 5.7% 5.7% 5.8%Weighted-average borrowing rate5.8 %5.7 %5.8 %5.8 %
Our weighted-average interest rates and weighted average borrowing rates for the three and nine months ended September 30, 2019, and 2018, wereare impacted by the timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility under the Credit Agreement, andfacility. Additionally, our weighted-average interest rates are impacted by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect amounts associated with the repurchaseearly redemption of Seniorcertain of our Old Notes, such as the premium paid upon repurchase, or the acceleration of
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unamortized deferred financing costs, expensed upon repurchase.as these amounts are netted against the associated gain or loss on extinguishment of debt. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During the ninesix months ended SeptemberJune 30, 2019,2020, we spent $788.6$310.2 million on capital expenditures. This amount differs from the costs incurred amount of $861.4$301.4 million for the ninesix months ended SeptemberJune 30, 2019,2020, as costs incurred is an accrual-based amount 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 acquisitions, our cash flows from operating, investing, and financing activities, and our ability to execute our development program.program, and the number and size of acquisitions. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, 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. We entered 2020 with a total capital program budgeted to be between $825 million and $850 million. However, given the macroeconomic events discussed throughout this report, we currently expect to reduce our 2020 capital program budget by approximately 25 percent for the full year 2020. We are unable to reasonably estimate the period of time that these market conditions will exist, the extent of the impact they will have on our business, liquidity, results of operations, financial condition, or the timing of any subsequent recovery. We will continue to monitor the economic environment throughout the year and adjust our activity level as warranted.
We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a combination of both. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. Repurchases or exchanges are reviewed as part of the allocation of our capital. During the thirdfirst quarter of 2018, the Company redeemed its 2021 Senior Notes, repurchased or redeemed all of its 2023 Senior Notes,2020, we repurchased a portiontotal of its$40.7 million of our 2022 Senior Notes in open market transactions at a discount, resulting in a net gain on extinguishment of debt of $12.2 million. During the second quarter of 2020, we completed the Exchange Offers which resulted in the exchange of $718.9 million in aggregate principal amount of Old Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes, as well as, in connection with the Private Exchange, (a) $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes, which was borrowed against our revolving credit facility, and issued its 2027 Senior Notes. We have not conducted similar debt transactions through September 30, 2019,(b) warrants to acquire up to an aggregate of approximately 5.9 million shares, or throughapproximately five percent of our outstanding common stock, exercisable upon the filingoccurrence of this report.certain future triggering events. Please refer to Note 5 - Long-Term Debt and Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion. As part of our strategy for 2020, we expect to continue to focus on improving our debt metrics, which could include further reducing the amount of our outstanding debt.
As of the filing 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 negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing each series of our outstanding Senior Notes, the indenture governing our Senior Convertible Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During the ninesix months ended SeptemberJune 30, 2019,2020, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of 2019.2020.
Analysis of Cash Flow Changes Between the NineSix Months Ended SeptemberJune 30, 2019,2020, and 20182019
The following tables present changes in cash flows between the ninesix months ended SeptemberJune 30, 2019,2020, and 2018,2019, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying unaudited condensed consolidated statements of cash flows in Part I, Item 1 of this report.

Operating activities
For the Six Months Ended
June 30,		Amount Change Between Periods
20202019
(in millions)
Net cash provided by operating activities$332.5  $378.4  $(45.9) 
 For the Nine Months Ended
September 30,		 Amount Change Between Periods
 2019 2018 
 (in millions)
Net cash provided by operating activities$581.6
 $541.2
 $40.4
DerivativeThe decrease in net cash settlements increased $125.9 million for the nine months ended September 30, 2019, compared with the same periodprovided by operating activities primarily consists of a decrease in 2018. This increase was partially offset by decreased cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes of $80.7$114.2 million, and increasedan increase in cash paid for LOE and ad valorem taxes of $22.2$10.6 million, for the nine months ended September 30, 2019, compared with the same periodan increase in 2018. Cashcash paid for interest decreased $11.3of $14.7 million, for the nine months ended September 30, 2019, compared with the same period in 2018, due to the redemption and repurchase of certain senior notes in the third quarter of 2018, partially offset by increased interest paid on the 2027 Senior Notes and interest paid on credit facility borrowings during the nine months ended September 30, 2019. Net cash provided by operating activities is also affected byas well as working capital changes and the timing of cash receipts and disbursements.
Investing activities
 For the Nine Months Ended
September 30,		 Amount Change Between Periods
 2019 2018 
 (in millions)
Net cash used in investing activities$(778.7) $(314.0) $(464.7)
The increase in cash used in investing activitiesdisbursements for the ninesix months ended SeptemberJune 30, 2019,2020, compared with the same period in 2018, is due to a decrease2019. These
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decreases in proceeds from the sale of oil and gas properties of $730.7 million. This decrease iscash provided by operating activities are partially offset by a decrease in capital expenditures and a decreasean increase of $182.8 million in cash paid to acquire proved and unproved oil and gas properties of $243.9 million and $22.0 million, respectively.
Financing activities
 For the Nine Months Ended
September 30,		 Amount Change Between Periods
 2019 2018 
 (in millions)
Net cash provided by (used in) financing activities$122.7
 $(364.4) $487.1
Net cash provided by (used in) financing activities increased $487.1 millionreceived from settled derivative trades for the ninesix months ended SeptemberJune 30, 2019,2020, compared with the same period in 2018. During2019.
Investing activities
For the Six Months Ended
June 30,		Amount Change Between Periods
20202019
(in millions)
Net cash used in investing activities$(310.1) $(563.3) $253.2  
Net cash used in investing activities decreased for the ninesix months ended SeptemberJune 30, 2020, compared with the same period in 2019, primarily due to reduced capital expenditures of $265.9 million.
Financing activities
For the Six Months Ended
June 30,		Amount Change Between Periods
20202019
(in millions)
Net cash provided by (used in) financing activities$(22.4) $113.3  $(135.7) 
Net cash used in financing activities for the six months ended June 30, 2020 related to debt issuance costs incurred upon the issuance of the 2025 Senior Secured Notes and net cash paid to repurchase certain of our Senior Unsecured Notes. Net cash provided by financing activities for the six months ended June 30, 2019 netwas driven by borrowings under our credit facility increased $129.0 million. Our credit facility remained undrawn throughout 2018. used to fund capital expenditures.
During the nine months ended September 30, 2018,first quarter of 2020, we redeemed $344.6repurchased a total of $40.7 million in aggregate principal outstanding on our 2021 Senior Notes, and repurchased $395.0 million principal outstanding of our 2023 Senior Notes and $85.0 million principal outstandingamount of our 2022 Senior Notes. As a result, premiums totaling $20.4 million wereNotes in open market transactions for cash paid, in connection with these redemptions and repurchases. Additionally, we issued our 2027 Senior Notes for net proceedsexcluding interest, of $492.1$28.3 million. There were no such debt transactions related to our Senior Notes during the nine months ended September 30,same period in 2019. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
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 SeptemberJune 30, 2019,2020, we had a $129.0$193.0 million balance on our revolving 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 market 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 market 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 Unsecured Notes or fixed-rate Senior ConvertibleSecured Notes but can impact their fair market values. As of SeptemberJune 30, 2019,2020, our outstanding principal amount of fixed-rate debt totaled $2.6$2.3 billion and our floating-rate debt outstanding totaled $129.0$193.0 million. Please refer to Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Secured Notes and Senior ConvertibleUnsecured Notes.

Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, 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, including changes in supply and demand and other factors thatthe macroeconomic environment, all of which are typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several years,months and these marketsyears. In recent months, oil, gas, and NGL prices weakened to historic lows as a result of various macroeconomic events and will likely continue to be volatile in the future. 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 ninesix months ended SeptemberJune 30, 2019,2020, 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 $83.6$41.1 million, $19.4$7.6 million, and $10.6$3.7 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the ninesix months ended SeptemberJune 30, 2019,2020, would have offset the declines in oil, gas, and NGL production revenue by approximately $53.0$37.8 million.
We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of SeptemberJune 30, 2019,2020, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $92.2$105.2 million, $8.1$21.1 million, and $5.1$1.7 million, respectively.
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Off-Balance Sheet Arrangements
As part of our ongoing business, we 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 during the ninesix months ended SeptemberJune 30, 2019,2020, 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 20182019 Form 10-K for discussion of our accounting policies and estimates.
New Accounting Pronouncements
Please refer to Note 1 - Summary of Significant Accounting Policies under Part I, Item 1 of this report for new accounting pronouncements.

Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest income, 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 non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe 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 the Credit Agreement section in Overview of Liquidity and Capital Resources above. 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 total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, 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.
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The following table provides reconciliations of our net income (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,		For the Three Months Ended
June 30,		For the Six Months Ended
June 30,

2019 2018 2019 20182020201920202019

(in thousands)(in thousands)
Net income (loss) (GAAP)$42,234
 $(135,923) $(84,946) $198,675
Net income (loss) (GAAP)$(89,252) $50,388  $(501,147) $(127,180) 
Interest expense40,584
 38,111
 118,191
 122,850
Interest expense40,354  39,627  81,866  77,607  
Income tax expense (benefit)16,111
 (36,748) (16,337) 61,342
Income tax expense (benefit)(36,685) 13,590  (135,693) (32,448) 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion211,125
 201,105
 595,201
 483,343
Depletion, depreciation, amortization, and asset retirement obligation liability accretion180,856  206,330  414,345  384,076  
Exploration (1)
10,341
 11,490
 30,070
 36,768
Exploration (1)
8,696  9,586  19,088  19,729  
Abandonment and impairment of unproved properties6,337
 9,055
 25,092
 26,615
ImpairmentImpairment8,750  12,417  998,513  18,755  
Stock-based compensation expense6,766
 7,004
 18,758
 17,680
Stock-based compensation expense5,712  6,154  11,273  11,992  
Net derivative (gain) loss(100,889) 178,026
 (3,463) 249,304
Net derivative (gain) loss167,200  (79,655) (378,140) 97,426  
Derivative settlement gain (loss)24,722
 (40,718) 23,843
 (101,911)Derivative settlement gain (loss)142,528  4,090  215,965  (879) 
Net gain on divestiture activity—
 (786) (323) (425,656)Net gain on divestiture activity(91) (262) (91) (323) 
Loss on extinguishment of debt—
 26,722
 —
 26,722
Gain on extinguishment of debtGain on extinguishment of debt(227,281) —  (239,476) —  
Other, net434
 (1,265) 1,129
 (4,519)Other, net703  691  1,036  695  
Adjusted EBITDAX (non-GAAP)257,765

256,073
 707,215
 691,213
Adjusted EBITDAX (non-GAAP)201,490  262,956  487,539  449,450  
Interest expense(40,584) (38,111) (118,191) (122,850)Interest expense(40,354) (39,627) (81,866) (77,607) 
Income tax (expense) benefit(16,111) 36,748
 16,337
 (61,342)Income tax (expense) benefit36,685  (13,590) 135,693  32,448  
Exploration (1)
(10,341)
(11,490) (30,070) (36,768)
Exploration (1)
(8,696) 

(9,586) (19,088) (19,729) 
Amortization of debt discount and deferred financing costs3,921
 3,792
 11,554
 11,542
Amortization of debt discount and deferred financing costs4,586  3,844  8,578  7,633  
Deferred income taxes19,617
 (36,833) (13,620) 60,672
Deferred income taxes(36,921) 13,766  (136,268) (33,237) 
Other, net(1,438) 1,483
 (3,420) 2,435
Other, net(3,714) 552  (4,863) (1,982) 
Net change in working capital(9,673) 17,997
 11,781
 (3,725)Net change in working capital(38,737) 41,613  (57,254) 21,454  
Net cash provided by operating activities (GAAP)$203,156

$229,659
 $581,586
 $541,177
Net cash provided by operating activities (GAAP)$114,339  $259,928  $332,471  $378,430  

(1)
(1)Stock-based compensation expense is a component of exploration expense and general and administrative expense 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 on Form 10-Q (“Form 10-Q”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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,” “pending,” “plan,” “project,” “target,” “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 future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
any changes to the borrowing base or aggregate lender commitments under our Credit Agreement;
our outlook on future oil, gas, and NGL prices, well costs, service costs,exploration expense and general and administrative costs;
expense line items on the drillingaccompanying statements of wells and otheroperations. Therefore, the exploration and development activities and plans by us, our joint development partners, and/or other third-party operators, 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 reserve estimates;
future oil, gas, and NGL production estimates;
cash flows, anticipated liquidity, interest and related debt service expenses, changesline items shown in the Company’s effective tax rate, andreconciliation above will vary from the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growthamount shown on the accompanying statements of operations or to defer capital investment, plans with respect to future dividend payments, 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 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 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 2018 Form 10-K, and include without limitation such factors as:
domestic and foreign supply of oil, natural gas, and NGLs;
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, consumer demand, 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, and that development of our proved undeveloped reserves may take longer and may require greater capital expenditures than we anticipate;
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, expertise and availability of third-party service providers and equipment for our operated activities;
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 our success in integrating new assets, and whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;component of stock-based compensation expense recorded to exploration expense.
the uncertainties associated with enhanced recovery methods;
43
our commodity derivative contracts expose us to counterparty credit risk and 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 oil, gas, NGL, or water to contractual counterparties;
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;
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;
the possibility of security threats, including terrorist attacks and cybersecurity attacks and breaches, against, or otherwise impacting, our facilities and systems;
operating and environmental risks and hazards that could result in substantial losses;
the impact of extreme weather conditions, laws and regulations, 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, delays, 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; 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 Risk and Commodity Price Risk in Item 2 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place underin 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 Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 20182019 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 are 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 and our Chief 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, but 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 are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the thirdsecond quarter of 20192020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, 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 expected to have a materially adverse effect upon our financial condition, results of operations or cash flows.
SPM NAM LLC. et al., v. SM Energy Company, Case No. 2018-07160, in the 189th Judicial District of Harris County, Texas.The case remains in discovery and the original trial date of June 22, 2020 was postponed in light of the Pandemic. As of the filing of this report, the trial is expected to begin during the fourth quarter of 2020. Please refer to Legal Proceedings in Part I, Item 3 of the 2019 Form 10-K for additional detail regarding this case.
Other than as described above, there have been no material changes to the legal proceedings as previously disclosed in our 2019 Form 10-K.
ITEM 1A. RISK FACTORS
The global COVID-19 Pandemic has impacted and will likely continue to impact us, and could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.
Since the beginning of 2020, the Pandemic has spread across the globe and disrupted economies around the world, including the oil, gas and NGL industry in which we operate. The rapid spread of the virus has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel, and other public health and safety measures, nearly all of which have materially reduced global demand for crude oil. The extent to which the Pandemic impacts will continue to affect our business, financial condition, liquidity, results of operations, prospects, and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information which may emerge concerning the severity of the Pandemic, and the effectiveness of actions taken to contain the coronavirus or treat its impact, such as development of a vaccine or other treatment protocol, now or in the future, among others.
Some impacts of the Pandemic that could have an adverse effect on our business, financial condition, liquidity and results of operations, include:
•significantly reduced prices for our oil, gas, and NGL production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;
•further decreases in the demand for our oil, gas, and NGL production, resulting from significantly decreased levels of global, regional and local travel as a result of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of the virus;
•the continuing possibility that we may further voluntarily curtail or shut-in production, resulting from depressed oil prices, lack of storage, and other market or political forces, or that we may curtail or shut-in production as a result of third-party and regulatory mandates;
•increased costs associated with, or actual unavailability of, facilities for the storage of oil, gas, and NGL production, in the markets in which we operate;
•increased operational difficulties associated with, or an inability to, deliver oil, gas, and NGLs to end-markets, resulting from pipeline and storage constraints;
•the potential for loss of leasehold or asset value for failure to produce oil and gas in paying quantities as a result of significantly lower commodity prices, or failures or difficulties in bringing shut-in wells back online at their prior production levels, or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing;
•increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, gas, and NGL production, resulting from adverse market conditions, a lack of access to capital and the failure of certain of our counterparties to continue as going concerns;
•increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions;
•decreased ability to access the capital markets or other sources of capital;
•cyber attacks or information security breaches resulting in information theft, data corruption, operational disruption, rendering data or systems unusable, and/or financial loss as a consequence of employees working and accessing information from remote work locations;
45

•increased costs and staffing requirements related to facility modifications, social distancing measures or other best practices implemented in connection with federal, state or local government, and voluntarily imposed quarantines or other regulations or guidelines concerning physical gatherings;
•risks associated with companies and/or individuals moving to a permanent remote work status such that certain elements of demand may never recover to previous, historic levels;
•loss of talent in our industry including technical personnel and other professionals as people pursue other industries; and
•increased legal and operational costs related to compliance with significant changes in federal, state, and local laws and regulations.
To the extent the Pandemic continues to adversely affect the global economy, and/or adversely affects our business, financial condition, liquidity, results of operations and prospects it may also increase the likelihood and/or magnitude of other risks described in Risk Factors in Part I, Item 1A of our 2019 Form 10-K and in this report, including those risks related to market, credit, geopolitical and business operations, or risks described in our other filings with the SEC. In addition, the Pandemic, or any recurrence of the outbreak may also affect our business, operations or financial condition in a manner that is not presently known to us or that we currently do not expect to present a significant risk to our business, operations, or financial condition. Also, the extent and duration of the impacts of macroeconomic events and the Pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors and, as a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired. Any such future developments are dependent upon factors including, but are not limited to, the duration and spread of the outbreak, its severity, any recurrence of the outbreak, the actions to contain the virus or treat its impact, the size and effectiveness of the compensating measures taken by governments, and how quickly and to what extent normal economic and operating conditions can resume.
The ability or willingness of the Organization of the Petroleum Exporting Countries (“OPEC”), Russia and other oil exporting nations to set, maintain and enforce production levels has a significant impact on oil, gas and NGL commodity prices, which could have a material adverse effect on our business, financial condition, liquidity and results of operations.
OPEC is an intergovernmental organization that seeks to manage the price and supply of oil and oil pricing on the global energy market. Actions taken by OPEC member countries, including those taken along with other oil exporting nations, have a significant impact on global oil supply and pricing. In March 2020, members of OPEC and ten other oil producing countries (“OPEC+”) met to discuss how to respond to the potential market effects of the Pandemic. The meeting ended in discord regarding production cuts and oil pricing among OPEC, Russia, and other oil exporting nations. These actions flooded the global market with an oversupply of crude oil, and led to an immediate and steep decrease in global oil prices. In early April 2020, in response to significantly depressed global oil prices, 23 countries, led by Saudi Arabia, Russia and the United States, committed to implement reductions in world oil production.
There can be no assurance that measures to limit global production will stabilize oil prices or that they will be maintained. The impacts of the Pandemic continue to be unpredictable and future case surges or outbreaks may continue to have further negative effects on global oil demand, despite the concerted action to reduce global production. Further, there is a lack of transparency regarding production volumes among oil-producing nations, and there are limited enforcement mechanisms for real or perceived violations of the production cuts. In connection with past production cuts, OPEC has at times failed to enforce its own production limits on violating members, with no official mechanism for punishing member countries that do not comply. There can be no assurance that OPEC and non-OPEC member countries will abide by the quotas or that OPEC will enforce the quotas. Additionally, certain other countries with free-market economies that agreed to reduce production, are unable to impose mandatory production cuts on non-OPEC oil producers operating in their countries, but instead expect to realize a decrease in production through market forces, as companies tend to cut production voluntarily when prices drop. For such countries, there can be no assurance that oil producers will react in the desired manner or that the market will behave as expected. Uncertainty regarding the effectiveness and enforcement of the production cuts is likely to lead to increased volatility in the supply and demand of oil and the price of oil, all of which could have a material adverse effect on our business, financial condition, liquidity and results of operations.
If we cannot continue to meet the continued listing requirements of the New York Stock Exchange (the “NYSE”), the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock and allow holders of our 2021 Senior Secured Convertible Notes to require us to repurchase their notes.
Pursuant to the NYSE Listed Company Manual, a company will be considered to be out of compliance with the NYSE’s continued listing standards if the average trading price of its common stock over any consecutive 30-trading-day period falls below $1.00 per share, which is the minimum average closing price required to maintain listing on the NYSE. While we continue to maintain compliance with the minimum average closing price required to maintain listing on the NYSE through the filing of this report, if we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-day period, the NYSE may delist our common stock for failure to maintain compliance with the NYSE price criteria listing standards. NYSE rules provide issuers six months from NYSE notification of a deficiency to cure noncompliance with the stock price listing standard before the NYSE begins suspension and delisting procedures. An issuer can regain compliance at any time during the six-month cure period if, on the last trading day of any calendar month during the cure period, the company has a closing stock price of at least $1.00 and an average
46

closing stock price of at least $1.00 over the 30-trading-day period ending on the last trading day of that month. However, there can be no assurance that we would be able to regain compliance during such cure period.
A delisting of our common stock from the NYSE could negatively impact us by, among other things: reducing the liquidity and market price of our common stock; reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; decreasing the number of equity analysts that cover and report on our common stock, which could further reduce the number of investors willing to hold or acquire our common stock; and limiting our ability to issue additional securities or obtain additional financing in the future. In addition, delisting from the NYSE is likely to negatively impact our reputation and, as a consequence, our business.
Further, if our common stock is delisted by the NYSE (and we are not eligible to become listed on other specified exchanges), holders of our 2021 Senior Secured Convertible Notes would have a right to require us to repurchase the 2021 Senior Secured Convertible Notes at a purchase price equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon. As of June 30, 2020, $65.5 million aggregate principal amount of the 2021 Senior Secured Convertible Notes was outstanding, and there can be no assurance we would have sufficient funds available to us to repurchase the 2021 Senior Secured Convertible Notes put to us if required to do so in connection with a delisting. Failure to repurchase the 2021 Senior Secured Convertible Notes put to us could, subject to a 60-day right to cure set forth in the 2021 Notes Indenture, result in (a) an event of default under the supplemental indenture, and (b) the potential acceleration of our obligation to repay all outstanding 2021 Senior Secured Convertible Notes, and could cause a cross-default under our other outstanding indebtedness, which could result in the foreclosure on the collateral securing our secured debt. As a result, we could be forced into bankruptcy or liquidation.
The depressed price of our common stock and market capitalization, resulting from the current macroeconomic environment and historically low commodity prices, could cause the Company to be subject to an unsolicited or hostile acquisition bid, which could result in substantial costs and diversion of management attention.
Due to the currently constrained macroeconomic environment and historically low commodity prices, the price of our common stock and market capitalization are significantly depressed. A relatively low stock price may cause us to become subject to an unsolicited or hostile acquisition bid, or other change in control. There can be no assurance that a third-party will not make an unsolicited takeover proposal in the future or take other action to acquire control of us or to otherwise influence our management and policies. Although we have certain anti-takeover measures in place, we have not adopted a shareholder rights plan, commonly known as a poison pill. The lack of this particular anti-takeover measure could make a change in control of us easier to accomplish.
Considering and responding to any future acquisition proposal or other stockholder action designed to acquire control, including the litigation that often accompanies such actions, is likely to be costly and time-consuming. Evaluating and addressing these overtures would require the time and attention of our management and Board of Directors, divert them from their focus on our business, and require us to incur additional expenses on outside legal, financial and other advisors, all of which could materially and adversely affect our business, financial condition and results of operations. Further, in the event that such an unsolicited or hostile bid is publicly disclosed, it may result in increased speculation and volatility in the price of our common stock.
There have been no other material changes to the risk factors as previously disclosed in our 20182019 Form 10-K.10-K, our Form 10-Q for the quarter ended March 31, 2020, and our 2020 Proxy Statement.
47

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table provides information aboutThere were no purchases made by us andor any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended SeptemberJune 30, 2019,2020, 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:Act.
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 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. 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 Secured Notes and Senior Unsecured Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. During the three months ended June 30, 2020, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of 2020.
PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
Period
Total Number of Shares Purchased (1)
Weighted Average Price Paid per ShareTotal Number of Shares Purchased as Part of Publicly Announced Program
Maximum Number of Shares that May Yet Be Purchased Under the Program (2)
07/01/2019 - 07/31/2019130,992
$12.52
—
3,072,184
08/01/2019 - 08/31/2019—
$—
—
3,072,184
09/01/2019 - 09/30/2019—
$—
—
3,072,184
Total:130,992
$12.52
—
3,072,184

(1)
All shares purchased by us in the third quarter of 2019 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs issued under the terms of award agreements granted under the 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 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. 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 flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time.
Our payment of cash dividends to our stockholders is subject to certain covenants under the terms of our Credit Agreement, Senior Secured Notes, and Senior ConvertibleUnsecured Notes. Based on our current performance, we do not anticipate that any of these covenants will limit our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.
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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)
First4.3
Third Amendment to the Sixth Amended and Restated Credit Agreement, dated April 18, 201929, 2020, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the institutions named therein as Lenders that are party thereto (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and incorporated herein by reference)
10.3
Second Amendment to Sixth Amended and Restated Credit Agreement, dated September 19, 2019June 17, 2020 among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent,priority lien agent, and the Lenders party theretoUMB Bank, N.A., as second lien collateral trustee (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on September 24, 2019,June 17, 2020, and incorporated herein by reference)
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.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.
†Exhibit constitutes a management contract or compensatory plan or agreement.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereuntothereunto duly authorized.
SM ENERGY COMPANY
July 31, 2020SM ENERGY COMPANY
By:
November 1, 2019By:/s/ JAVAN D. OTTOSON
Javan D. Ottoson
President and Chief Executive Officer
(Principal Executive Officer)
November 1, 2019July 31, 2020By:By:/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
November 1, 2019July 31, 2020By:By:/s/ PATRICK A. LYTLE
Patrick A. Lytle
Controller and Assistant Secretary
(Principal Accounting Officer)

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