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•	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.

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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 revenue	11,334				15,592				29,376				49,521				40,710				65,113
NGL production revenue	58				21				21,772				36,281				21,830				36,302
Total	$	287,528			$	240,860			$	66,705			$	99,616			$	354,233			$	340,476
Relative percentage	81		%		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 no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of 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 no 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 no 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 benefit	99,347				47,003
Income tax benefit	$	99,008			$	46,038
Effective tax rate	19.4		%		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

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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 Loans	0.750	%		1.000	%		1.500	%		1.750	%		2.000	%
Commitment Fee Rate	0.375	%		0.375	%		0.500	%		0.500	%		0.500	%

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(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 capacity	1,006,500				1,128,000				1,077,500
Total aggregate lender commitment amount	$	1,100,000			$	1,200,000			$	1,200,000

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(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 2024	500,000				3,535				496,465				500,000				3,766				496,234
5.625% Senior Notes due 2025	500,000				4,677				495,323				500,000				4,903				495,097
6.75% Senior Notes due 2026	500,000				5,362				494,638				500,000				5,571				494,429
6.625% Senior Notes due 2027	500,000				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

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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.

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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 zero 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 zero to two 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 one 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

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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 cost	698				656
Expected return on plan assets that reduces periodic pension benefit cost	(393		)		(466		)
Amortization of prior service cost	4				4
Amortization of net actuarial loss	240				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-dilutive	1,219			781

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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 outstanding	113,009				112,252
Dilutive effect of non-vested RSUs and contingent PSUs	—				—
Diluted weighted-average common shares outstanding	113,009				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

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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

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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 assets	44,909				20,624
Total derivative assets	$	508,901			$	75,808
Derivative liabilities:
Current liabilities	$	8,277			$	50,846
Noncurrent liabilities	7,202				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	)

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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 contracts	6,728				(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.

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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 no 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. No proved property impairment expense was recorded during the three months ended March 31, 2019.

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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

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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
2021	12,541
2022	5,745
2023	3,602
2024	2,081
Thereafter	1,640
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.

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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.

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•	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.

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(1)	Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells.

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(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.

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(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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(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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•	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.

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(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.

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