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SM SM Energy



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 March 31, 2020

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
smenergylogohorizontalaa08.jpg
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)
 Delaware 41-0518430 
 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 
 1775 Sherman Street, Suite 1200,Denver,Colorado 80203 
 (Address of principal executive offices) (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 class Trading symbol(s) Name of each exchange on which registered
Common stock, $0.01 par value SM New 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 
       
 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 April 22, 2020, the registrant had 112,988,682 shares of common stock outstanding.



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TABLE OF CONTENTS


2


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, 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 the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic on us, 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;
the 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;
the drilling of wells and other exploration and development activities, the 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 venture relating to, certain properties;
oil, gas, and NGL 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, identified drilling locations, as well as drilling prospects, inventories, projects and programs;
cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;
plans, objectives, expectations and intentions; 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”) and in 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.


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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share data)
 March 31,
2020
 December 31,
2019
ASSETS   
Current assets: �� 
Cash and cash equivalents$15
 $10
Accounts receivable143,311
 184,732
Derivative assets463,992
 55,184
Prepaid expenses and other17,842
 12,708
Total current assets625,160
 252,634
Property and equipment (successful efforts method):   
Proved oil and gas properties8,043,156
 8,934,020
Accumulated depletion, depreciation, and amortization(4,389,103) (4,177,876)
Unproved oil and gas properties972,844
 1,005,887
Wells in progress224,509
 118,769
Other property and equipment, net of accumulated depreciation of $64,815 and $64,032, respectively36,932
 72,848
Total property and equipment, net4,888,338
 5,953,648
Noncurrent assets:   
Derivative assets44,909
 20,624
Other noncurrent assets56,618
 65,326
Total noncurrent assets101,527
 85,950
Total assets$5,615,025
 $6,292,232
LIABILITIES AND STOCKHOLDERS' EQUITY   
Current liabilities:   
Accounts payable and accrued expenses$359,406
 $402,008
Derivative liabilities8,277
 50,846
Other current liabilities15,780
 19,189
Total current liabilities383,463
 472,043
Noncurrent liabilities:   
Revolving credit facility72,000
 122,500
Senior Notes, net of unamortized deferred financing costs2,413,663
 2,453,035
Senior Convertible Notes, net of unamortized discount and deferred financing costs159,721
 157,263
Asset retirement obligations85,267
 84,134
Deferred income taxes93,918
 189,386
Derivative liabilities7,202
 3,444
Other noncurrent liabilities58,074
 61,433
Total noncurrent liabilities2,889,845
 3,071,195
    
Commitments and contingencies (note 6)


 


    
Stockholders’ equity:   
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,988,682 and 112,987,952 shares, respectively1,130
 1,130
Additional paid-in capital1,797,154
 1,791,596
Retained earnings554,562
 967,587
Accumulated other comprehensive loss(11,129) (11,319)
Total stockholders’ equity2,341,717
 2,748,994
Total liabilities and stockholders’ equity$5,615,025
 $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
March 31,
 2020 2019
Operating revenues and other income:   
Oil, gas, and NGL production revenue$354,233
 $340,476
Net gain on divestiture activity
 61
Other operating revenues1,501
 393
Total operating revenues and other income355,734

340,930
Operating expenses:




Oil, gas, and NGL production expense119,552
 121,305
Depletion, depreciation, amortization, and asset retirement obligation liability accretion233,489
 177,746
Exploration11,349
 11,348
Impairment989,763
 6,338
General and administrative27,447
 32,086
Net derivative (gain) loss(545,340) 177,081
Other operating expenses, net566
 335
Total operating expenses836,826

526,239
Loss from operations(481,092)
(185,309)
Interest expense(41,512) (37,980)
Gain on extinguishment of debt12,195
 
Other non-operating expense, net(494) (317)
Loss before income taxes(510,903)
(223,606)
Income tax benefit99,008
 46,038
Net loss$(411,895)
$(177,568)
 




Basic weighted-average common shares outstanding113,009
 112,252
Diluted weighted-average common shares outstanding113,009
 112,252
Basic net loss per common share$(3.64) $(1.58)
Diluted net loss per common share$(3.64) $(1.58)
Dividends per common share$0.01
 $0.05
The accompanying notes are an integral part of these condensed consolidated financial statements.

5


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
(in thousands)
 For the Three Months Ended
March 31,
 2020 2019
Net loss$(411,895) $(177,568)
Other comprehensive income, net of tax:   
Pension liability adjustment190
 263
Total other comprehensive income, net of tax190
 263
Total comprehensive loss$(411,705) $(177,305)

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 Capital   Accumulated Other Comprehensive Loss Total Stockholders’ Equity
 Common Stock  Retained Earnings  
 Shares Amount    
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

   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

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

7


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
 For the Three Months Ended
March 31,
 2020 2019
Cash flows from operating activities:   
Net loss$(411,895) $(177,568)
Adjustments to reconcile net loss to net cash provided by operating activities   
Net gain on divestiture activity
 (61)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion233,489
 177,746
Impairment989,763
 6,338
Stock-based compensation expense5,561
 5,838
Net derivative (gain) loss(545,340) 177,081
Derivative settlement gain (loss)73,437
 (4,969)
Amortization of debt discount and deferred financing costs3,992
 3,789
Gain on extinguishment of debt(12,195) 
Deferred income taxes(99,347) (47,003)
Other, net(816) (2,530)
Net change in working capital(18,517) (20,159)
Net cash provided by operating activities218,132
 118,502
    
Cash flows from investing activities:   
Net proceeds from the sale of oil and gas properties
 6,114
Capital expenditures(139,306) (249,340)
Other, net
 291
Net cash used in investing activities(139,306) (242,935)
    
Cash flows from financing activities:   
Proceeds from revolving credit facility425,500
 172,000
Repayment of revolving credit facility(476,000) (125,500)
Cash paid to repurchase 6.125% Senior Notes due 2022(28,318) 
Other, net(3) (18)
Net cash provided by (used in) financing activities(78,821) 46,482
    
Net change in cash, cash equivalents, and restricted cash5
 (77,951)
Cash, cash equivalents, and restricted cash at beginning of period10
 77,965
Cash, cash equivalents, and restricted cash at end of period$15
 $14
    
Supplemental schedule of additional cash flow information and non-cash activities:   
    
Operating activities:   
Cash paid for interest, net of capitalized interest$(47,469) $(39,957)
    
Investing activities:   
Increase in capital expenditure accruals and other$16,802
 $62,185
    
Supplemental non-cash investing activities:   
Carrying value of properties exchanged$
 $65,788

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

8


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 oil, gas, and NGLs in 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 2019 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 March 31, 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 2019 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 2019 Form 10-K.
Recently Issued Accounting Standards
In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2019-12, Income Taxes (Topic 740): 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 to franchise taxes, which should be applied on either a retrospective basis for all periods presented or 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 2019-12 on January 1, 2020, and there was no material impact on the 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 is evaluating the options provided by ASU 2020-04. Please refer to Note 5 - Long-Term Debt for discussion of the use of the London Interbank Offered Rate (“LIBOR”) in connection with borrowings under the Credit Agreement.
As disclosed in the 2019 Form 10-K, 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 on January 1, 2020. 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 March 31, 2020, and through the filing of this report.

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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. 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 table below presents oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three months ended March 31, 2020, and 2019:
 Midland Basin South Texas Total
 Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31,
 2020 2019 2020 2019 2020 2019
 (in thousands)
Oil production revenue$276,136
 $225,247
 $15,557
 $13,814
 $291,693
 $239,061
Gas production revenue11,334
 15,592
 29,376
 49,521
 40,710
 65,113
NGL production revenue58
 21
 21,772
 36,281
 21,830
 36,302
Total$287,528
 $240,860
 $66,705
 $99,616
 $354,233
 $340,476
Relative percentage81% 71% 19% 29% 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 differs 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. When control is transferred at or near the wellhead, sales are based on a wellhead market price that is impacted by fees and other deductions incurred by the purchaser subsequent to the transfer of control. Please refer to Note 2 - Revenue from Contracts with Customers in the 2019 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.
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 unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of March 31, 2020, and December 31, 2019, were $62.0 million and $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.
Note 3 - Divestitures, Assets Held for Sale, and Acquisitions
Divestitures
No material divestitures occurred during the first quarters of 2020 and 2019, and there were 0 assets classified as held for sale as of March 31, 2020, or December 31, 2019.

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Acquisitions
No material acquisitions or acreage trades of oil and gas properties occurred during the first quarter of 2020. During the first quarter 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 2,000 net acres, with $65.8 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with 0 gain or loss recognized.
Note 4 - Income Taxes
The provision for income taxes for the three months ended March 31, 2020, and 2019, consisted of the following:
 For the Three Months Ended March 31,
 2020 2019
 (in thousands)
Current portion of income tax (expense) benefit:   
Federal$
 $
State(339) (965)
Deferred portion of income tax benefit99,347
 47,003
Income tax benefit$99,008
 $46,038
Effective tax rate19.4% 20.6%

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 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 above.
A 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.
The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The primary feature of the CARES Act that the Company will benefit from is the acceleration of its refundable Alternative Minimum Tax (“AMT”) credits. On April 1, 2020, the Company filed an election to accelerate its remaining refundable AMT credits of $7.6 million that are expected to be received during the second quarter of 2020.
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 April 29, 2020, the Company and its lenders entered into the Third Amendment to the Credit Agreement (“Third Amendment”). The Company’s Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion. Also on April 29, 2020, as a result of the regular semi-annual borrowing base redetermination, the borrowing base and aggregate lender commitments were both reduced to $1.1 billion due to a decrease in the value of proved reserves driven by decreased commodity pricing. The Third Amendment permits the Company to incur second lien debt of up to $900.0 million (“Permitted Lien Debt”) prior to the next scheduled redetermination date of October 1, 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 par value. Additionally, the Third Amendment reduces the limit on the amount of dividends that the Company may declare and pay on an annual basis from $50.0 million to $12.0 million. The Third Amendment also amends certain other covenants of the Company in the Credit Agreement.
The Credit Agreement is scheduled to mature on September 28, 2023, except that, pursuant to the Third Amendment, upon the Company’s incurrence of Permitted Lien Debt to redeem the 6.125% Senior Notes due 2022 (“2022 Senior Notes”), the maturity date under the Credit Agreement will be July 2, 2023. Without regard to which maturity date is in effect, the maturity date could occur earlier on August 16, 2022, if the Company has not completed certain repurchase, redemption, or refinancing activities associated with its 2022 Senior Notes, and does not have certain unused availability for borrowing under the Credit Agreement, as outlined in the Credit

11


Agreement and the Third Amendment. 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 March 31, 2020, and through the filing of this report.
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 borrowing base utilization grid was amended by the Third Amendment as presented in the table below. Please refer to Note 5 - Long-Term Debt in the 2019 Form 10-K for the utilization grid in effect prior to the Third Amendment. 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 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. Please refer to Note 5 - Long-Term Debt in the 2019 Form 10-K for additional detail on the terms of the Company’s Credit Agreement.
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 in the event that LIBOR is no longer a widely used benchmark rate, or that 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 filing on April 29, 2020, March 31, 2020, and December 31, 2019:
 As of filing on April 29, 2020 As of March 31, 2020 As of December 31, 2019
 (in thousands)
Revolving credit facility (1)
$93,500
 $72,000
 $122,500
Letters of credit
 
 
Available borrowing capacity1,006,500
 1,128,000
 1,077,500
Total aggregate lender commitment amount$1,100,000
 $1,200,000
 $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 $5.5 million and $5.9 million as of March 31, 2020, and December 31, 2019, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis.
Senior Notes
The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of March 31, 2020, and December 31, 2019, consisted of the following:
 As of March 31, 2020 As of December 31, 2019
 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$436,047
 $2,442
 $433,605
 $476,796
 $2,920
 $473,876
5.0% Senior Notes due 2024500,000
 3,535
 496,465
 500,000
 3,766
 496,234
5.625% Senior Notes due 2025500,000
 4,677
 495,323
 500,000
 4,903
 495,097
6.75% Senior Notes due 2026500,000
 5,362
 494,638
 500,000
 5,571
 494,429
6.625% Senior Notes due 2027500,000
 6,368
 493,632
 500,000
 6,601
 493,399
Total$2,436,047
 $22,384
 $2,413,663
 $2,476,796
 $23,761
 $2,453,035

The senior notes listed above (collectively referred to as the “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

12


future subordinated debt. There are no subsidiary guarantors of any of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes and was in compliance with all covenants as of March 31, 2020, and through the filing of this report. The Company may redeem some or all of its Senior 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 Notes. Please refer to Note 5 - Long-Term Debt in the 2019 Form 10-K for additional detail on the Company’s Senior Notes.
During the first quarter of 2020, the Company repurchased a total of $40.7 million in aggregate principal amount of its 2022 Senior Notes in open market transactions for a total settlement amount, excluding accrued interest, of $28.3 million. In connection with the repurchase, the Company recorded a gain on extinguishment of debt of $12.2 million for the three months ended March 31, 2020. This amount included discounts realized upon repurchase of $12.4 million partially offset by approximately $235,000 of accelerated unamortized deferred financing costs. The Company canceled all repurchased 2022 Senior Notes upon cash settlement.
Senior Convertible Notes
As of March 31, 2020, the Company’s senior convertible notes consisted 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 2019 Form 10-K for additional detail on the Company’s Senior Convertible Notes and associated capped call transactions.
The Senior Convertible Notes were not convertible at the option of holders as of March 31, 2020, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of March 31, 2020, did not exceed the principal amount. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.9 million and $2.7 million for the three months ended March 31, 2020, and 2019, respectively.
There have been no changes to the initial net carrying amount 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 of unamortized discount and deferred financing costs line on the accompanying balance sheets as of March 31, 2020, and December 31, 2019, consisted of the following:
 As of March 31, 2020 As of December 31, 2019
 (in thousands)
Principal amount of Senior Convertible Notes$172,500
 $172,500
Unamortized debt discount(11,633) (13,861)
Unamortized deferred financing costs(1,146) (1,376)
Senior Convertible Notes, net of unamortized discount and deferred financing costs$159,721
 $157,263

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of March 31, 2020, and through the filing of this report.
Capitalized Interest
Capitalized interest costs for the three months ended March 31, 2020, and 2019, totaled $2.7 million and $4.9 million, 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 2019 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the 2019 Form 10-K for additional discussion of the Company’s commitments.
Subsequent to March 31, 2020, 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 $22.3 million. If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $12.9 million in early termination fees. The Company does not expect to incur material penalties with regard to its drilling rig contracts.

13


Subsequent to March 31, 2020, the Company entered into an agreement that included minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2021, the Company would be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. The liquidated damages could range from 0 to a maximum of $42.0 million, with the maximum exposure assuming no development activity occurred prior to March 31, 2021. As of the filing of this report, the Company expects to meet its obligations under this agreement.
Contingencies
The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. 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 March 31, 2020, 4.5 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 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 performance 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 granted in 2017, which the Company has determined to be equity awards, the settlement criteria include 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 2017 was measured on the grant date 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 include 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 measures, 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 $2.6 million and $2.8 million for the three months ended March 31, 2020, and 2019, respectively. As of March 31, 2020, there was $12.9 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2022. There have been no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2020.
Employee Restricted Stock Units
The Company grants restricted stock units (“RSUs”) to eligible persons as part of its 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. RSUs generally vest one-third of the total 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 periods of the respective awards. Total compensation expense recorded for employee RSUs was $2.6 million and $2.7 million for the

14


three months ended March 31, 2020, and 2019, respectively. As of March 31, 2020, there was $13.6 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2022. There have been no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2020.
Please refer to Note 7 - Compensation Plans in the 2019 Form 10-K for additional detail on the Company’s Equity Plan.
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 Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of 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
March 31,
 2020 2019
 (in thousands)
Components of net periodic benefit cost:   
Service cost$1,395
 $1,683
Interest cost698
 656
Expected return on plan assets that reduces periodic pension benefit cost(393) (466)
Amortization of prior service cost4
 4
Amortization of net actuarial loss240
 332
Net periodic benefit cost$1,944
 $2,209

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 expense, net line item on the accompanying statements of operations.
Contributions
As of the filing of this report, the Company has contributed $3.3 million to the Qualified Pension Plan in 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. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are 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 for the three months ended March 31, 2020, and 2019, therefore, the Senior Convertible Notes had no dilutive impact. Please refer to Note 9 - Earnings Per Share in the 2019 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 March 31,
 2020 2019
 (in thousands)
Anti-dilutive1,219
 781


15


The following table sets forth the calculations of basic and diluted net loss per common share:
 For the Three Months Ended March 31,
 2020 2019
 (in thousands, except per share data)
Net loss$(411,895) $(177,568)
    
Basic weighted-average common shares outstanding113,009
 112,252
Dilutive effect of non-vested RSUs and contingent PSUs
 
Diluted weighted-average common shares outstanding113,009
 112,252
    
Basic net loss per common share$(3.64) $(1.58)
Diluted net loss per common share$(3.64) $(1.58)

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 March 31, 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 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 New 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 has basis swaps 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.
As of March 31, 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
  (MBbl) (per Bbl)
Second quarter 2020 2,838
 $58.81
Third quarter 2020 3,361
 $56.43
Fourth quarter 2020 4,397
 $57.03
2021 2,085
 $45.70
Total 12,681
  

16


Oil Collars
Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price
  (MBbl) (per Bbl) (per Bbl)
Second quarter 2020 1,881
 $55.00
 $62.17
Third quarter 2020 1,252
 $55.00
 $62.90
Fourth quarter 2020 610
 $55.00
 $61.90
2021 329
 $55.00
 $56.70
Total 4,072
    
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)
  (MBbl) (per Bbl) (MBbl) (per Bbl)
Second quarter 2020 3,637
 $(0.62) 910
 $(8.06)
Third quarter 2020 3,607
 $(0.62) 920
 $(8.01)
Fourth quarter 2020 4,087
 $(0.38) 920
 $(8.01)
2021 11,527
 $0.87
 3,650
 $(7.86)
2022 9,500
 $1.15
 3,650
 $(7.78)
Total 32,358
   10,050
  
____________________________________________
(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).
Gas Swaps
Contract Period IF HSC Volumes 
Weighted-Average
 Contract Price
 WAHA Volumes Weighted-Average Contract Price
  (BBtu) (per MMBtu) (BBtu) (per MMBtu)
Second quarter 2020 4,160
 $2.20
 3,592
 $0.63
Third quarter 2020 4,493
 $2.41
 4,294
 $1.07
Fourth quarter 2020 6,994
 $2.32
 4,516
 $1.20
2021 28,621
 $2.29
 17,533
 $1.45
2022 6,104
 $2.23
 
 $
Total (1)
 50,372
   29,935
  
____________________________________________
(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 March 31, 2020, WAHA volumes were comprised of 81 percent IF WAHA and 19 percent GD WAHA.
NGL Swaps
  OPIS Ethane Purity Mont Belvieu OPIS Propane Mont Belvieu Non-TET
Contract Period Volumes 
Weighted-Average
 Contract Price
 Volumes Weighted-Average
Contract Price
  (MBbl) (per Bbl) (MBbl) (per Bbl)
Second quarter 2020 264
 $11.13
 382
 $22.34
Third quarter 2020 
 $
 409
 $22.33
Fourth quarter 2020 
 $
 466
 $22.29
Total 264
   1,257
  


17


Commodity Derivative Contracts Entered Into Subsequent to March 31, 2020
Subsequent to March 31, 2020, the Company entered into the following commodity derivative contracts:
fixed price NYMEX WTI oil swap contracts for 2021 for a total of 5.5 MMBbl of oil production at a weighted-average contract price of $37.57 per Bbl;
fixed price IF HSC gas swap contracts for 2021 for a total of 6,197 BBtu of gas production at a weighted-average contract price of $2.42 per MMBtu;
fixed price IF WAHA gas swap contracts through the fourth quarter of 2021 for a total of 2,437 BBtu of gas production at a weighted-average contract price of $1.57 per MMBtu; and
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”) for the second quarter of 2020 through the fourth quarter of 2021 for a total of 6.8 MMBbl of oil production, in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price of $(1.24) per Bbl; the weighted average price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.
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 $493.4 million and $21.5 million as of March 31, 2020, and December 31, 2019, respectively.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:
 As of March 31, 2020 As of December 31, 2019
 (in thousands)
Derivative assets:   
Current assets$463,992
 $55,184
Noncurrent assets44,909
 20,624
Total derivative assets$508,901
 $75,808
Derivative liabilities:   
Current liabilities$8,277
 $50,846
Noncurrent liabilities7,202
 3,444
Total derivative liabilities$15,479
 $54,290
Offsetting of Derivative Assets and Liabilities
As of March 31, 2020, and December 31, 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 as of Derivative Liabilities as of
 March 31, 2020 December 31, 2019 March 31, 2020 December 31, 2019
 (in thousands)
Gross amounts presented in the accompanying balance sheets$508,901
 $75,808
 $(15,479) $(54,290)
Amounts not offset in the accompanying balance sheets(15,479) (35,075) 15,479
 35,075
Net amounts$493,422
 $40,733
 $
 $(19,215)


18


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 March 31,
 2020 2019
 (in thousands)
Derivative settlement (gain) loss:   
Oil contracts$(53,582) $1,369
Gas contracts(14,625) 4,134
NGL contracts(5,230) (534)
Total derivative settlement (gain) loss$(73,437) $4,969
    
Net derivative (gain) loss:   
Oil contracts$(542,540) $185,797
Gas contracts6,728
 (6,113)
NGL contracts(9,528) (2,603)
Total net derivative (gain) loss$(545,340) $177,081

Credit Related Contingent Features
As of March 31, 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 unobservable
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of March 31, 2020:

Level 1
Level 2
Level 3

(in thousands)
Assets:     
Derivatives (1)
$
 $508,901
 $
Total property and equipment, net (2)
$
 $
 $380,734
Liabilities:     
Derivatives (1)
$
 $15,479
 $
__________________________________________
(1) 
This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2) 
This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

19


The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2019:
 Level 1 Level 2 Level 3
 (in thousands)
Assets:     
Derivatives (1)
$
 $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 2019 Form 10-K for more information regarding the Company’s derivative instruments.
Oil and Gas Properties and Other Property and Equipment
Amounts reflected in the total property and equipment, net line item, measured at fair value within the accompanying balance sheets totaled $380.7 million as of March 31, 2020. The Company had 0 assets included in total property and equipment, net, measured at fair value as of December 31, 2019.
Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses an income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are 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. Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on the 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 cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets.
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, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities during the three months ended March 31, 2020. The Company used a discount rate of 11 percent in its calculation of the present value of expected future cash flows based on the prevailing market-based weighted average cost of capital as of March 31, 2020. NaN proved property impairment expense was recorded during the three months ended March 31, 2019.

20


The following table presents impairment of oil and gas properties expense and abandonment and impairment of unproved properties expense recorded for the periods presented:
 For the Three Months Ended
March 31,
 2020 2019
 (in millions)
Impairment of proved oil and gas properties and related support equipment$956.7
 $
Abandonment and impairment of unproved properties (1)
33.1
 6.3
Impairment$989.8
 $6.3
____________________________________________
(1) 
These impairments 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. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of March 31, 2020, and December 31, 2019, are recorded at carrying value.
Please refer to Note 1 - Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the 2019 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 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 March 31, 2020, or December 31, 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 March 31, 2020 As of December 31, 2019
 Principal Amount Fair Value Principal Amount Fair Value
 (in thousands)
6.125% Senior Notes due 2022$436,047
 $190,771
 $476,796
 $481,564
5.0% Senior Notes due 2024$500,000
 $148,750
 $500,000
 $479,815
5.625% Senior Notes due 2025$500,000
 $145,000
 $500,000
 $475,835
6.75% Senior Notes due 2026$500,000
 $150,000
 $500,000
 $494,860
6.625% Senior Notes due 2027$500,000
 $149,215
 $500,000
 $493,750
1.50% Senior Convertible Notes due 2021$172,500
 $69,576
 $172,500
 $164,430

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.
Note 12 - Leases
ASC Topic 842 - Leases (“Topic 842”), requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. As of March 31, 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.
As outlined in Topic 842, an 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. 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. 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 the nature and use of the underlying ROU asset and in accordance with GAAP requirements.
Please refer to Note 12 - Leases in the 2019 Form 10-K for more information regarding the Company's policy on leases, and assumptions and judgments made in the initial and subsequent measurement of lease ROU assets and corresponding 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

21


terms range from less than one year to approximately six 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 ten 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. 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.
For the three months ended March 31, 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 $72.7 million and $175.3 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 months ended March 31, 2020, and 2019, consisted of the following:
 For the Three Months Ended March 31,
 2020 2019
 (in thousands)
Operating lease cost$6,834
 $8,979
Short-term lease cost (1)
43,572
 134,917
Variable lease cost (2)
22,334
 31,408
Total lease cost$72,740
 $175,304
____________________________________________
(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.
Other information related to the Company’s leases for the three months ended March 31, 2020, and 2019, was as follows:
 For the Three Months Ended March 31,
 2020 2019
 (in thousands)
Cash paid for amounts included in the measurement of lease liabilities:   
Operating cash flows from operating leases$3,046
 $2,952
Investing cash flows from operating leases$3,980
 $6,182
Right-of-use assets obtained in exchange for new operating lease liabilities$
 $12,191

Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of March 31, 2020, were as follows:
 As of March 31, 2020
 (in thousands)
2020 (remaining after March 31, 2020)$13,997
202112,541
20225,745
20233,602
20242,081
Thereafter1,640
Total Lease payments$39,606
Less: Imputed interest (1)
(3,816)
Total$35,790
____________________________________________
(1) 
The weighted-average discount rate used to determine the operating lease liability as of March 31, 2020, was 6.7 percent.

22


Amounts recorded on the accompanying balance sheets for operating leases as of March 31, 2020, and December 31, 2019, were as follows:
 As of March 31, 2020 As of December 31, 2019
 (in thousands)
Other noncurrent assets$33,365
 $39,717
    
Other current liabilities$15,780
 $19,189
Other noncurrent liabilities$20,010
 $23,137

As of March 31, 2020, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.

23


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 section of this report for important information about these types of statements.
Overview of the Company
General Overview
Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision is to sustainably grow value for all of our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top tier assets. At present, our investment portfolio is focused on high quality oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in South Texas.
Areas of Operations
Our Midland Basin assets are located in the Permian Basin in West Texas and are comprised of approximately 80,000 net acres (“Midland Basin”). In the first quarter of 2020, we focused on continuing to delineate, develop, and expand our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
Our South Texas assets are comprised of approximately 158,900 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 formation and delineating the Austin Chalk 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.
First Quarter 2020 Overview and Outlook for the Remainder of 2020
The competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic have simultaneously increased supply and decreased demand for oil, gas, and NGLs to historic extremes, and have impacted our entire industry. The implications of these unprecedented events continue to unfold and may have further negative effects to our business such as production curtailment, reduced storage capacity, and reductions to our operating plans. For additional detail, please refer to Risk Factors in Part II, Item 1A of this report and those risk factors previously disclosed in our 2019 Form 10-K.
While we were impacted by these macroeconomic events in the first quarter of 2020, specifically the impacts to the realized prices we receive for our production, and will likely be impacted to a greater degree for the remainder of 2020, we expect to maintain our current ability to sustain strong operational performance and financial stability. 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 and delineation. We believe our assets provide significant production growth potential and returns that are capable of providing internally generated cash flows in low commodity price environments, which support our priorities of improving leverage metrics and maintaining financial flexibility. Our financial risk management program has significantly reduced the impact of substantially lower oil prices in 2020 as a significant amount of our total expected 2020 oil production is covered by derivative contracts at prices greater than or equal to $55.00 per barrel. However, further negative impacts resulting from these events, such as production curtailments and storage capacity constraints, could limit our ability to deliver production and capitalize on the value of our derivative contracts in 2020 and beyond. Given the dynamic nature of the macroeconomic events discussed above, 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.
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. Energy production was deemed an essential business amidst the global COVID-19 pandemic. While the execution of our business operations requires certain individuals to be physically present at well site locations, we implemented processes and protocols where substantially all of our office based people are working remotely in order to restrict physical interactions to mitigate the spread of COVID-19. For individuals who are unable to perform their jobs remotely, we have implemented social distancing measures and continue to communicate and train our employees to maintain a healthy and safe work environment. Since these measures have been implemented, we continue to operate at a very high level without significant disruptions to our ability to operate our business or our control environment.
The information below summarizes our recent operating and financial performance and our expectations for the remainder of 2020, including our liquidity position.

24


We entered 2020 with a total capital program budgeted to be between $825 million and $850 million. However, given the circumstances discussed above, as of the filing of this report we expect to reduce our 2020 capital program budget by approximately 20 percent for the full year 2020. Our financial and operational flexibility allows us to continually monitor the economic environment throughout the year and adjust our activity level as warranted. Our 2020 program remains focused on our most economic oil development projects in both our Midland Basin and South Texas assets. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund our 2020 capital program.
Financial and Operational Results. Average net daily production for the three months ended March 31, 2020, was 135.9 MBOE, compared with 118.7 MBOE for the same period in 2019. This increase was driven by a 32 percent increase in average net daily production volumes from our Midland Basin assets. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased seven percent, 44 percent, and 30 percent, respectively, for the three months ended March 31, 2020, compared with the same period in 2019. As a result of increased production, oil, gas, and NGL production revenue increased four percent to $354.2 million for the three months ended March 31, 2020, compared with $340.5 million for the same period in 2019. The increase in oil, gas, and NGL production revenue due to increased production was largely offset by decreased pricing. We recorded a net derivative gain of $545.3 million for the three months ended March 31, 2020, compared to a net derivative loss of $177.1 million recorded for the same period in 2019. Included within these derivative amounts is a gain of $73.4 million on derivative contracts that settled during the three months ended March 31, 2020, and a loss of $5.0 million for the same period in 2019. Total production costs on a per BOE basis decreased 15 percent to $9.67 per BOE for the three months ended March 31, 2020, from $11.35 per BOE for the same period in 2019. Overall financial and operational activities during the three months ended March 31, 2020, resulted in the following:
net cash provided by operating activities of $218.1 million for the three months ended March 31, 2020, compared with $118.5 million for the same period in 2019. Please refer to Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2020, and 2019 below for additional discussion;
net loss of $411.9 million, or $3.64 per diluted share, for the three months ended March 31, 2020, compared with a net loss of $177.6 million, or $1.58 per diluted share, for the same period in 2019. The net loss for the three months ended March 31, 2020, was primarily driven by impairment expense of $989.8 million, partially offset by a net derivative gain of $545.3 million. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and 2019 below for additional discussion regarding the components of net loss for each period presented; and
adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2020, was $286.0 million, compared with $186.5 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 some of the impacts resulting from the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic. We maintain flexibility to continually monitor the economic environment throughout the year and make related adjustments as warranted.
In our Midland Basin program, we operated five drilling rigs and two completion crews during the first quarter of 2020. We drilled 25 gross (22 net) wells and completed 19 gross (19 net) wells during the first quarter of 2020, and increased average net daily production volumes year-over-year by 32 percent to 83.4 MBOE per day, 78 percent of which was oil. Costs incurred for oil and gas producing activities in our Midland Basin program during the three months ended March 31, 2020, were $138.7 million, or 83 percent of our total costs incurred for that period. Subsequent to March 31, 2020, we released one completion crew and plan to reduce activity to four drilling rigs in July 2020. These plans are subject to change in response to market conditions. 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 Spraberry and Wolfcamp A shale intervals.
In our South Texas program, we operated one drilling rig during the first quarter of 2020. We drilled three gross (three net) wells and completed one gross (one net) well during the first quarter of 2020. Average net daily production for the first quarter of 2020 was 52.5 MBOE, a five percent decrease year-over-year. Costs incurred for oil and gas producing activities in our South Texas program during the three months ended March 31, 2020, were $17.9 million, or 11 percent of our total costs incurred for that period. For the remainder of 2020, we anticipate operating one drilling rig and, at times during the year, one completion crew in South Texas. These plans are subject to change in response to market conditions. Drilling and completion activities in South Texas continue to focus on developing the Eagle Ford shale formation and delineating the Austin Chalk formation.


25


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 months ended March 31, 2020:
 Midland Basin South Texas Total
 Gross Net Gross Net Gross Net
Wells drilled but not completed at December 31, 201951
 48
 21
 21
 72
 69
Wells drilled25
 22
 3
 3
 28
 25
Wells completed(19) (19) (1) (1) (20) (20)
Other (1)

 1
 
 
 
 1
Wells drilled but not completed at March 31, 202057
 52
 23
 23
 80
 75
____________________________________________
(1) 
Includes adjustments related to normal business activities, including 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 $167.4 million for the three months ended March 31, 2020, and were incurred in our Midland Basin and South Texas programs as further detailed under 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 March 31, 2020, and 2019:
 Midland Basin South Texas Total
 Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31,
 2020 2019 2020 2019 2020 2019
Production:           
Oil (MMBbl)5.9
 4.5
 0.4
 0.3
 6.3
 4.8
Gas (Bcf)9.9
 6.9
 16.6
 17.0
 26.5
 23.9
NGLs (MMBbl)
 
 1.6
 1.9
 1.6
 1.9
Equivalent (MMBOE)7.6
 5.7
 4.8
 5.0
 12.4
 10.7
Avg. daily equivalents (MBOE/d)83.4
 63.3
 52.5
 55.5
 135.9
 118.7
Relative percentage61% 53% 39% 47% 100% 100%
____________________________________________
Note: Amounts may not calculate due to rounding.
Please refer to Three Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and 2019 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 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.

26


The following table summarizes commodity price data, as well as the effects of derivative settlements, for the first quarter of 2020 as well as the fourth and first quarters of 2019:
 For the Three Months Ended
 March 31, 2020 December 31, 2019 March 31, 2019
Oil (per Bbl):     
Average NYMEX contract monthly price$46.17
 $56.96
 $54.90
Realized price, before the effect of derivative settlements$45.96
 $56.09
 $49.47
Effect of oil derivative settlements$8.44
 $(0.87) $(0.28)
Gas:     
Average NYMEX monthly settle price (per MMBtu)$1.95
 $2.50
 $3.15
Realized price, before the effect of derivative settlements (per Mcf)$1.54
 $2.42
 $2.73
Effect of gas derivative settlements (per Mcf)$0.55
 $0.33
 $(0.18)
NGLs (per Bbl):     
Average OPIS price (1)
$17.02
 $21.96
 $26.28
Realized price, before the effect of derivative settlements$13.62
 $17.84
 $19.39
Effect of NGL derivative settlements$3.27
 $6.09
 $0.28
____________________________________________
(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 future benchmark prices for oil, gas, and NGLs to remain depressed due to the severe demand declines and global over-supply resulting from the impacts of the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic. 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. Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and beyond. Please refer to First 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 (same product mix as discussed under the table above) as of April 22, 2020, and March 31, 2020:
 As of April 22, 2020 As of March 31, 2020
NYMEX WTI oil (per Bbl)$25.58
 $29.82
NYMEX Henry Hub gas (per MMBtu)$2.55
 $2.16
OPIS NGLs (per Bbl)$13.27
 $12.30
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, 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 derivatives is driven by the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity contracts. With our current derivative commodity contracts, we believe we have partially reduced our exposure to volatility in commodity prices and location 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.

27


Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended March 31, 2020, and the preceding three quarters.
 For the Three Months Ended
 March 31, December 31, September 30, June 30,
 2020 2019 2019 2019
 (in millions)
Production (MMBOE)12.4
 12.8
 12.4
 12.4
Oil, gas, and NGL production revenue$354.2
 $449.0
 $389.4
 $406.9
Oil, gas, and NGL production expense$119.6
 $127.3
 $129.0
 $123.1
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$233.5
 $228.7
 $211.1
 $206.3
Exploration$11.3
 $17.7
 $11.6
 $10.9
General and administrative$27.4
 $37.2
 $32.6
 $30.9
Net income (loss)$(411.9) $(102.1) $42.2
 $50.4
____________________________________________
Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
 For the Three Months Ended
 March 31, December 31, September 30, June 30,
 2020 2019 2019 2019
Average net daily production equivalent (MBOE per day)135.9
 138.8
 134.9
 136.5
Lease operating expense (per BOE)$4.75
 $4.67
 $4.73
 $4.16
Transportation costs (per BOE)$3.11
 $3.46
 $4.00
 $4.00
Production taxes as a percent of oil, gas, and NGL production revenue4.2% 4.2% 4.1% 4.0%
Ad valorem tax expense (per BOE)$0.60
 $0.37
 $0.39
 $0.44
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)$18.88
 $17.91
 $17.02
 $16.61
General and administrative (per BOE)$2.22
 $2.92
 $2.63
 $2.49
____________________________________________
Note: Amounts may not calculate due to rounding.

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Three Month Overview of Selected Production and Financial Information, Including Trends
 For the Three Months Ended March 31, Amount Change Between Periods Percent Change Between Periods
 2020 2019 
Net production volumes: (1)
       
Oil (MMBbl)6.3
 4.8
 1.5
 31 %
Gas (Bcf)26.5
 23.9
 2.6
 11 %
NGLs (MMBbl)1.6
 1.9
 (0.3) (14)%
Equivalent (MMBOE)12.4
 10.7
 1.7
 16 %
Average net daily production: (1)
       
Oil (MBbl per day)69.8
 53.7
 16.1
 30 %
Gas (MMcf per day)291.2
 265.5
 25.7
 10 %
NGLs (MBbl per day)17.6
 20.8
 (3.2) (15)%
Equivalent (MBOE per day)135.9
 118.7
 17.2
 14 %
Oil, gas, and NGL production revenue (in millions): (1)
       
Oil production revenue$291.7
 $239.1
 $52.6
 22 %
Gas production revenue40.7
 65.1
 (24.4) (37)%
NGL production revenue21.8
 36.3
 (14.5) (40)%
Total oil, gas, and NGL production revenue$354.2
 $340.5
 $13.8
 4 %
Oil, gas, and NGL production expense (in millions): (1)
       
Lease operating expense$58.8
 $55.6
 $3.2
 6 %
Transportation costs38.4
 43.6
 (5.1) (12)%
Production taxes14.9
 14.0
 0.8
 6 %
Ad valorem tax expense7.4
 8.1
 (0.7) (8)%
Total oil, gas, and NGL production expense$119.6
 $121.3
 $(1.8) (1)%
Realized price, before the effect of derivative settlements:       
Oil (per Bbl)$45.96
 $49.47
 $(3.51) (7)%
Gas (per Mcf)$1.54
 $2.73
 $(1.19) (44)%
NGLs (per Bbl)$13.62
 $19.39
 $(5.77) (30)%
Per BOE$28.64
 $31.86
 $(3.22) (10)%
Per BOE data:       
Production costs:       
Lease operating expense$4.75
 $5.20
 $(0.45) (9)%
Transportation costs$3.11
 $4.08
 $(0.97) (24)%
Production taxes$1.20
 $1.31
 $(0.11) (8)%
Ad valorem tax expense$0.60
 $0.76
 $(0.16) (21)%
Total production costs (1)
$9.67
 $11.35
 $(1.68) (15)%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$18.88
 $16.63
 $2.25
 14 %
General and administrative$2.22
 $3.00
 $(0.78) (26)%
Derivative settlement gain (loss) (2)
$5.94
 $(0.47) $6.41
 1,364 %
Earnings per share information:       
Basic weighted-average common shares outstanding (in thousands)113,009
 112,252
 757
 1 %
Diluted weighted-average common shares outstanding (in thousands)113,009
 112,252
 757
 1 %
Basic net loss per common share$(3.64) $(1.58) $(2.06) 130 %
Diluted net loss per common share$(3.64) $(1.58) $(2.06) 130 %
______________________________________
(1) 
Amount and percentage changes may not calculate due to rounding.
(2) 
Derivative settlements for the three months ended March 31, 2020, and 2019, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

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Average daily equivalent production for the three months ended March 31, 2020, increased 14 percent compared with the same period in 2019. This increase was driven by a 32 percent increase in average daily equivalent production volumes from our Midland Basin assets for the three months ended March 31, 2020, compared with the same period in 2019. Average daily equivalent production volumes from our South Texas assets decreased five percent for the three months ended March 31, 2020, compared with the same period in 2019. For the full year 2020, we expect total production volumes to decline compared with 2019.
We present certain information on a per BOE basis in 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 10 percent for the three months ended March 31, 2020, compared with the same period in 2019, primarily driven by lower benchmark commodity prices for oil, gas, and NGLs. This decrease was partially offset by an increase in oil production as a percentage of total production from 45 percent for the three months ended March 31, 2019, to 51 percent for the three months ended March 31, 2020. Regional pricing differentials in the Midland Basin negatively affected our realized prices in 2019 and are expected to continue to negatively affect our realized prices in 2020. For the three months ended March 31, 2020, we recognized a gain of $5.94 per BOE, on the settlement of our derivative contracts, compared to a recognized loss of $0.47 per BOE for the three months ended March 31, 2019.
Lease operating expense (“LOE”) on a per BOE basis decreased nine percent for the three months ended March 31, 2020, compared with the same period in 2019. This decrease was primarily driven by increased production and continued efforts to reduce costs as part of our operating plan. For the full year 2020, we expect LOE on a per BOE basis to be higher compared with 2019 as our product mix continues to shift towards more oil production. 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 industry activity, all of which impacts service provider costs.
Transportation costs on a per BOE basis decreased 24 percent for the three months ended March 31, 2020, compared with the same period in 2019. This decrease was driven by a five percent reduction in average daily equivalent production volumes from our South Texas assets for the three months ended March 31, 2020, compared with the same period in 2019, and a 32 percent increase in 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. On a per BOE basis, we expect transportation costs to decrease in 2020, compared with 2019, as production from our Midland Basin assets continues to become a larger portion of our total production.
Production taxes on a per BOE basis decreased eight percent for the three months ended March 31, 2020, compared with the same period in 2019. This decrease was primarily driven by a decrease in realized prices and an increase in oil production volumes as a percent of total production volumes. Our overall production tax rate for each of the three months ended March 31, 2020, and 2019 was 4.2 percent and 4.1 percent, respectively. We expect our overall production tax rate to remain consistent in 2020, compared with 2019. 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 21 percent for the three months ended March 31, 2020, compared with the same period in 2019, resulting from changes in our asset and production base. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as a result of continuing changes in the valuation of our producing properties.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased 14 percent for the three months ended March 31, 2020, compared with the same period in 2019. This increase was 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. 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. We expect DD&A expense on a per BOE basis to decrease for the remainder of 2020 compared with the three months ended March 31, 2020, and compared with the year ended December 31, 2019, as a result of a reduction in the depletable cost basis of our proved oil and gas properties resulting from proved property impairments during the three months ended March 31, 2020.
General and administrative (“G&A”) expense on a per BOE basis decreased 26 percent for the three months ended March 31, 2020, compared with the same period in 2019. This decrease is primarily due to increased production and the reorganization in the fourth quarter of 2019 of certain functions that eliminated duplicative regional operational functions and reduced overhead costs. For the full year 2020, we expect G&A expense to decrease compared with 2019.
Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and 2019 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 loss per common share calculations.

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Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and 2019
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 months ended March 31, 2020, and 2019:
 Net Equivalent Production
Increase (Decrease)
 Production Revenue
Increase (Decrease)
 Production Expense
Increase (Decrease)
 (MBOE per day) (in millions) (in millions)
Midland Basin20.1
 $46.7
 $7.5
South Texas(3.0) (32.9) (9.3)
Total17.2
 $13.8
 $(1.8)
__________________________________________
Note: Amounts may not calculate due to rounding.
We experienced a 14 percent increase in net equivalent daily production for the three months ended March 31, 2020, compared with the same period in 2019, primarily as a result of increased production from our Midland Basin assets. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased seven percent, 44 percent, and 30 percent, respectively, for the three months ended March 31, 2020, compared with the same period in 2019. As the increase in production slightly offset lower pricing, oil, gas, and NGL production revenue increased four percent for the three months ended March 31, 2020, compared with the same period in 2019.
Total production expense for the three months ended March 31, 2020, compared with the same period in 2019, decreased one percent. Decreases in transportation costs and ad valorem tax expense were offset by increases in lease operating expenses and production taxes. Please refer to Three Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including trends on a per BOE basis.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
 For the Three Months Ended March 31,
 2020 2019
 (in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion$233.5
 $177.7
DD&A expense increased 31 percent for the three months ended March 31, 2020, compared with the same period in 2019. This increase is directly related to the 32 percent increase in average daily equivalent production volumes from our Midland Basin assets as these assets have higher depletion rates than our assets in South Texas.
Exploration
 For the Three Months Ended March 31,
 2020 2019
 (in millions)
Geological and geophysical expenses$1.2
 $0.4
Overhead and other expenses10.1
 10.9
Total$11.3
 $11.3
Exploration expense remained flat for the three months ended March 31, 2020, compared with the same period in 2019. For the full year 2020, we expect exploration expense to decrease compared with 2019 as a result of lower overhead; however, exploration expense is impacted by actual geological and geophysical studies we perform and the potential for exploratory dry hole expense.

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Impairment
 For the Three Months Ended March 31,
 2020 2019
 (in millions)
Impairment of proved oil and gas properties and related support equipment$956.7
 $
Abandonment and impairment of unproved properties33.1
 6.3
Total$989.8
 $6.3
As a result of the decrease in commodity price forecasts at the end of the first quarter 2020, specifically decreases in oil and NGL prices, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities during the three months ended March 31, 2020. There were no proved oil and gas property impairments recorded for the same period in 2019. Unproved property abandonments and impairments recorded for the three months ended March 31, 2020, and 2019 related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks.
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.
Reserve estimates and related impairments of proved and unproved properties are difficult to predict in a volatile price environment. Due to the supply impacts associated with the competition between Russia and Saudi Arabia for crude oil market share and demand impacts associated with the global COVID-19 pandemic, we may experience additional proved and unproved property impairments in the future if commodity prices for the products we produce continue to decline. Given these current uncertainties in commodity prices and the associated impacts they may have on service provider costs, we cannot predict with any reasonable certainty the likelihood or magnitude of further property impairments beyond those recorded during the period ended March 31, 2020.
Please refer to Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion of impairment expense.
General and administrative
 For the Three Months Ended March 31,
 2020 2019
 (in millions)
General and administrative$27.4
 $32.1
G&A expense decreased 14 percent for the three months ended March 31, 2020, compared with the same period in 2019. Please refer to the section Three Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion of G&A expense in total and on a per BOE basis.
Net derivative (gain) loss
 For the Three Months Ended March 31,
 2020 2019
 (in millions)
Net derivative (gain) loss$(545.3) $177.1
We recognized a $545.3 million derivative gain for the three months ended March 31, 2020. The gain was primarily driven by a $471.9 million upward mark-to-market adjustment due to weakening oil prices during the first three months of 2020. There was a $73.4 million gain on derivative contracts that settled during the three months ended March 31, 2020.
We recognized a $177.1 million derivative loss for the three months ended March 31, 2019. This loss was primarily driven by a $172.1 million downward mark-to-market adjustment on derivative contracts settling subsequent to March 31, 2019, due to strengthening oil prices during the first three months of 2019. There was an additional loss of $5.0 million on derivative contracts that settled during the three months ended March 31, 2019.
Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

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Interest expense
 For the Three Months Ended March 31,
 2020 2019
 (in millions)
Interest expense$41.5
 $38.0
Interest expense increased nine percent for the three months ended March 31, 2020, compared with the same period in 2019 as a result of increased interest expense associated with borrowings against our revolving credit facility in 2020. We expect interest expense related to our Senior Notes to remain relatively flat for the remainder of 2020 compared with 2019; however, total interest expense will vary based on the timing and amount of borrowings against our revolving credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report and Overview of Liquidity and Capital Resources below for additional discussion.
Gain on extinguishment of debt
 For the Three Months Ended March 31,
 2020 2019
 (in millions)
Gain on extinguishment of debt$12.2
 $
We recorded a $12.2 million net gain on the early extinguishment of a portion of our 2022 Senior Notes during the three months ended March 31, 2020, which included discounts realized upon repurchase of $12.4 million partially 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 discussion.
Income tax benefit
 For the Three Months Ended March 31,
 2020 2019
 (in millions, except tax rate)
Income tax benefit$99.0
 $46.0
Effective tax rate19.4% 20.6%
The decrease in the effective tax rate for the three months ended March 31, 2020, compared with the same period in 2019, was primarily due to recording a valuation allowance for deferred tax assets we determined were not likely to be utilized after we recorded proved property impairments during the first quarter of 2020. The tax rates reflect proportional effects of changes to forecast income or loss and forecast changes to valuation allowances, excess tax deficiencies from stock-based compensation awards, and limits on expensing of certain covered individual’s compensation. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.
Overview of Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. 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.
Sources of Cash
We currently expect our 2020 capital program to be funded by cash flows from operations with any remaining cash needs being funded by borrowings under our revolving credit facility. During the three months ended March 31, 2020, we generated $218.1 million of cash flows from operating activities. As of filing on April 29, 2020, the remaining available borrowing capacity under our Credit Agreement provided $1.0 billion in liquidity; however, our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities. Please refer to Credit Agreement below for additional discussion.
Although we expect cash flows from these sources to be sufficient to fund our expected 2020 capital program, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly-issued securities may have rights, preferences, or privileges senior to those of existing stockholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. All of our

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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 recently downgraded 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.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion. 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. On April 29, 2020, we entered into the Third Amendment with our lenders, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were both reduced to $1.1 billion due to a decrease in the value of proved reserves as a result of decreased commodity pricing. The next scheduled borrowing base redetermination date is October 1, 2020. 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 available borrowing capacity under our Credit Agreement as of filing on April 29, 2020, March 31, 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 set 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 cannot be greater than 4.00 to 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 March 31, 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 loss and net cash provided by operating activities to adjusted EBITDAX.
Our daily weighted-average revolving credit facility debt balance was approximately $104.1 million and $12.1 million for the three months ended March 31, 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 in the event that LIBOR is no longer a widely used benchmark rate, or that 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 discount related to the Senior 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 months ended March 31, 2020, and 2019:
 For the Three Months Ended March 31,
 2020 2019
Weighted-average interest rate6.5% 6.5%
Weighted-average borrowing rate5.7% 5.8%

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Our weighted-average interest rates and weighted average borrowing rates are impacted by the timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. 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 repurchase of a portion of our 2022 Senior Notes, such as the discount realized or the acceleration of unamortized deferred financing costs expensed upon repurchase. 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 three months ended March 31, 2020, we spent $139.3 million on capital expenditures. This amount differs from the costs incurred amount of $167.4 million for the three months ended March 31, 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. 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 are 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 20 percent for the full year 2020. Given the dynamic nature of the macroeconomic events discussed throughout this report, 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. During the first quarter of 2020, we repurchased a total of $40.7 million of our 2022 Senior Notes in open market transactions at a discount, resulting in a gain on extinguishment of debt of $12.2 million. Additionally, we decreased the outstanding balance of our revolving credit facility by $50.5 million during the first quarter of 2020. Please refer to Note 5 - Long-Term Debt 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 our 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 three months ended March 31, 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.
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2020, and 2019
The following tables present changes in cash flows between the three months ended March 31, 2020, and 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 Three Months Ended
March 31,
 Amount Change Between Periods
 2020 2019 
 (in millions)
Net cash provided by operating activities$218.1
 $118.5
 $99.6

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Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes increased $105.7 million and cash received from settled derivative trades increased $19.5 million for the three months ended March 31, 2020, compared with the same period in 2019. These increases were partially offset by increased cash paid for LOE and ad valorem taxes of $16.3 million for the three months ended March 31, 2020, compared with the same period in 2019. Cash paid for interest increased $7.5 million for the three months ended March 31, 2020, compared with the same period in 2019. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Investing activities
 For the Three Months Ended
March 31,
 Amount Change Between Periods
 2020 2019 
 (in millions)
Net cash used in investing activities$(139.3) $(242.9) $103.6
Net cash used in investing activities decreased for the three months ended March 31, 2020, compared with the same period in 2019, primarily due to reduced capital expenditures of $110.0 million.
Financing activities
 For the Three Months Ended
March 31,
 Amount Change Between Periods
 2020 2019 
 (in millions)
Net cash provided by (used in) financing activities$(78.8) $46.5
 $(125.3)
Net cash used in financing activities increased $125.3 million for the three months ended March 31, 2020, compared with the same period in 2019. During the three months ended March 31, 2020, we repaid $50.5 million of our outstanding revolving credit facility balance, compared with increased borrowings of $46.5 million for the same period in 2019. During the first quarter of 2020, we repurchased a total of $40.7 million in aggregate principal amount of our 2022 Senior Notes in open market transactions for cash paid, excluding interest, of $28.3 million. There were no debt transactions related to our Senior Notes during the 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 March 31, 2020, we had a $72.0 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 value but will not impact results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes or fixed-rate Senior Convertible Notes but can impact their fair values. As of March 31, 2020, our outstanding principal amount of fixed-rate debt totaled $2.6 billion and our floating-rate debt outstanding totaled $72.0 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 Notes and Senior Convertible 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 unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the 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 months and years. In recent weeks, oil and NGL prices have weakened to historic lows as a result of the impacts of the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic. These prices 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 three months ended March 31, 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 $29.2 million, $4.1 million, and $2.2 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the three months ended March 31, 2020, would have offset the declines in oil, gas, and NGL production revenue by approximately $22.6 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

36


March 31, 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 $54.1 million, $16.1 million, and $1.8 million, respectively.
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 three months ended March 31, 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 2019 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.

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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 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 our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default.
The following table provides reconciliations of our net loss (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

For the Three Months Ended March 31,

2020 2019

(in thousands)
Net loss (GAAP)$(411,895) $(177,568)
Interest expense41,512
 37,980
Income tax benefit(99,008) (46,038)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion233,489
 177,746
Exploration (1)
10,392
 10,143
Impairment989,763
 6,338
Stock-based compensation expense5,561
 5,838
Net derivative (gain) loss(545,340) 177,081
Derivative settlement gain (loss)73,437
 (4,969)
Net gain on divestiture activity
 (61)
Gain on extinguishment of debt(12,195) 
Other, net333
 4
Adjusted EBITDAX (non-GAAP)286,049
 186,494
Interest expense(41,512) (37,980)
Income tax benefit99,008
 46,038
Exploration (1)
(10,392) (10,143)
Amortization of debt discount and deferred financing costs3,992
 3,789
Deferred income taxes(99,347) (47,003)
Other, net(1,149) (2,534)
Net change in working capital(18,517) (20,159)
Net cash provided by operating activities (GAAP)$218,132
 $118,502
____________________________________________
(1) 
Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

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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 in Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and is incorporated herein by reference. Please also refer to the information under Interest Rate 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 2019 Form 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, 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 first quarter of 2020 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 has been postponed in light of the global COVID-19 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 COVID-19 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 global COVID-19 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 global COVID-19 pandemic and the effectiveness of actions taken to contain the coronavirus or treat its impact now or in the future, among others.
Some impacts of the global COVID-19 pandemic that could have an adverse effect on our business, financial condition, liquidity and results of operations, include:
significantly reduced prices for our oil 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 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;
increased likelihood that we will, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut-in production, resulting from depressed oil prices, lack of storage, and other market or political forces;
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 and NGLs to end-markets, resulting from pipeline and storage constraints;
the potential for forced curtailment of oil and NGL production by state governmental agencies, resulting in a need to significantly curtail or shut-in our production;
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, voluntary or forced curtailments 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 and NGL production, resulting from adverse market conditions, a lack of access to capital and storage, 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;
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; and

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increased legal and operational costs related to compliance with significant changes in federal, state, and local laws and regulations.
To the extent the global COVID-19 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 have the effect of increasing 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 Form 10-Q, including those risks related to market, credit, geopolitical and business operations, or risks described in our other filings with the SEC. In addition, the global COVID-19 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. Additionally, the extent and duration of the impacts of the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 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 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 global COVID-19 pandemic. The meeting ended on March 6, 2020, as Saudi Arabia failed to convince Russia to reduce production to offset falling demand due to slowing economic activity resulting from the global COVID-19 pandemic. In response to Russia’s refusal to accept the production cut, Saudi Arabia announced an immediate reduction in its export prices and Russia announced that all previously agreed oil production cuts would expire on April 1, 2020. 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 the production cuts will stabilize oil prices or that they will be maintained, and recent indications suggest that oil prices will be largely unaffected. The global COVID-19 pandemic has destroyed global oil demand to an unprecedented degree, and despite the concerted action to reduce global production, the relative magnitude of the production cuts as compared to the degree of demand destruction may be wholly insufficient to mitigate or even impact the over-supplied oil market. 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.
We face risks associated with the forced curtailment of our production by state governmental agencies or others, which could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.
The Railroad Commission of Texas (the “Railroad Commission”) is a state agency that regulates oil and gas production in the state of Texas and has the power to curb production by private producers in order to conserve the state of Texas’ natural resources, to protect correlative rights and prevent waste, a power referred to as “proration.” As a result of the global COVID-19 pandemic and resulting oversupply of oil production and related significantly decreased prices, in April 2020, the Railroad Commission met to consider proration. As of the filing of this report, the Railroad Commission has not implemented proration, but is continuing to assess whether to invoke the power to enforce production limits to help stabilize the price of oil. At present, our investment portfolio is focused on high quality oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in South Texas. If the Railroad Commission implements proration in the state of Texas, any reduction in the level of our oil and NGL production could have a material adverse effect on our business, financial condition, liquidity and results of operations.
We may also be forced to curtail our production in response to the declining overall market for our production related to diminishing storage capacity available to the purchasers of our production, or to reduce economic loss.

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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 Senior 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 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 Senior Convertible Notes would have a right to require us to repurchase the Senior Convertible Notes at a purchase price equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon. As of March 31, 2020, $172.5 million aggregate principal amount of the Senior Convertible Notes was outstanding, and there can be no assurance we would have sufficient funds available to us to repurchase the Senior Convertible Notes put to us if required to do so in connection with a delisting. Failure to repurchase the Senior Convertible Notes put to us could, subject to a 60-day right to cure set forth in the supplemental indenture governing the Senior Convertible Notes, result in (a) an event of default under the supplemental indenture, and (b) the potential acceleration of our obligation to repay all outstanding Senior 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 2019 Form 10-K.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended March 31, 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:
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)
01/01/2020 - 01/31/2020175
$11.83

3,072,184
02/01/2020 - 02/29/2020
$

3,072,184
03/01/2020 - 03/31/2020166
$6.17

3,072,184
Total:341
$9.07

3,072,184
____________________________________________
(1) 
All shares purchased by us in the first quarter of 2020 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 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. During the three months ended March 31, 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.
Our payment of cash dividends to our stockholders is subject to certain covenants under the terms of our Credit Agreement, Senior Notes, and Senior Convertible 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
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.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 SM ENERGY COMPANY
   
April 29, 2020By:/s/ JAVAN D. OTTOSON
  Javan D. Ottoson
  President and Chief Executive Officer
  (Principal Executive Officer)
   
April 29, 2020By:/s/ A. WADE PURSELL
  A. Wade Pursell
  Executive Vice President and Chief Financial Officer
  (Principal Financial Officer)
   
April 29, 2020By:/s/ PATRICK A. LYTLE
  Patrick A. Lytle
  Controller and Assistant Secretary
  (Principal Accounting Officer)

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