sm-20210331

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, 2021

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

For the transition period from ___________ to ___________

Commission File Number 001-31539

SM 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 21, 2021, the registrant had 117,797,778 shares of common stock outstanding.

TABLE OF CONTENTS


Item		Page
	Cautionary Information about Forward-Looking Statements	3

	Part I	4

Item 1.	Financial Statements (unaudited)	4

	Condensed Consolidated Balance Sheets March 31, 2021, and December 31, 2020	4

	Condensed Consolidated Statements of Operations Three Months Ended March 31, 2021, and 2020	5

	Condensed Consolidated Statements of Comprehensive Loss Three Months Ended March 31, 2021, and 2020	6

	Condensed Consolidated Statements of Stockholders’ Equity Three Months Ended March 31, 2021, and 2020	7

	Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 2021, and 2020	8

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	39

	Part II	40

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

Item 6.	Exhibits	41

	Signatures	42

Cautionary Information about Forward-Looking Statements

This Report on Form 10-Q (“Form 10-Q” or “this report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements included in this report, other than statements of historical facts, that address activities, conditions, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:

•the impacts of the global COVID-19 pandemic (“Pandemic”) and the Texas Weather Event (as defined below) on us, our industry, our financial condition, and our results of operations;

•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;

•any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (“Credit Agreement”);

•our outlook on future crude oil, natural gas, and natural gas liquids (also referred to throughout this report as “oil,” “gas,” and “NGLs,” respectively) prices, well costs, service costs, production costs, and general and administrative costs;

•our drilling and completion activities and other exploration and development activities, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;

•possible or expected acquisitions and divestitures, including the possible divestiture or farmout of, or joint development of, certain properties;

•oil, gas, and NGL reserve estimates and estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;

•our expected future production volumes, identified drilling locations, as well as drilling prospects, inventories, projects and programs;

•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;

•business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations; and

•other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2 of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in the Risk Factors section in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”).

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.

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, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	10
Accounts receivable	199,631		162,455
Derivative assets	20,859		31,203
Prepaid expenses and other	9,792		10,001
Total current assets	230,282		203,669
Property and equipment (successful efforts method):
Proved oil and gas properties	8,735,538		8,608,522
Accumulated depletion, depreciation, and amortization	(5,051,876)		(4,886,973)
Unproved oil and gas properties	705,822		714,602
Wells in progress	291,146		233,498

Other property and equipment, net of accumulated depreciation of $64,242 and $63,662, respectively	31,986		32,217
Total property and equipment, net	4,712,616		4,701,866
Noncurrent assets:
Derivative assets	13,567		23,150
Other noncurrent assets	59,180		47,746
Total noncurrent assets	72,747		70,896
Total assets	$	5,015,645	$	4,976,431
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	394,226	$	371,670

Derivative liabilities	371,802		200,189
Other current liabilities	10,591		11,880
Total current liabilities	776,619		583,739
Noncurrent liabilities:
Revolving credit facility	135,000		93,000
Senior Notes, net	2,125,651		2,121,319


Asset retirement obligations	84,206		83,325


Derivative liabilities	67,595		22,331
Other noncurrent liabilities	56,902		56,557
Total noncurrent liabilities	2,469,354		2,376,532

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 114,742,304 shares as of March 31, 2021, and December 31, 2020	1,147		1,147
Additional paid-in capital	1,833,651		1,827,914
Retained earnings (deficit)	(51,719)		200,697
Accumulated other comprehensive loss	(13,407)		(13,598)
Total stockholders’ equity	1,769,672		2,016,160
Total liabilities and stockholders’ equity	$	5,015,645	$	4,976,431

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share data)


	For the Three Months Ended March 31,
		2021		2020
Operating revenues and other income:
Oil, gas, and NGL production revenue		$	423,165	$	354,233

Other operating income		20,681		1,501
Total operating revenues and other income		443,846		355,734
Operating expenses:
Oil, gas, and NGL production expense		100,930		119,552
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		166,960		233,489
Exploration		9,323		11,349

Impairment		8,750		989,763
General and administrative		24,714		27,447
Net derivative (gain) loss		344,689		(545,340)
Other operating expense, net		(599)		566
Total operating expenses		654,767		836,826
Loss from operations		(210,921)		(481,092)
Interest expense		(39,871)		(41,512)
Gain on extinguishment of debt		—		12,195
Other non-operating expense, net		(371)		(494)
Loss before income taxes		(251,163)		(510,903)
Income tax (expense) benefit		(106)		99,008
Net loss		$	(251,269)	$	(411,895)

Basic weighted-average common shares outstanding		114,759		113,009
Diluted weighted-average common shares outstanding		114,759		113,009
Basic net loss per common share		$	(2.19)	$	(3.64)
Diluted net loss per common share		$	(2.19)	$	(3.64)
Dividends per common share		$	0.01	$	0.01

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)

(in thousands)


	For the Three Months Ended March 31,
		2021		2020
Net loss		$	(251,269)	$	(411,895)
Other comprehensive income, net of tax:
Pension liability adjustment		191		190
Total other comprehensive income, net of tax		191		190
Total comprehensive loss		$	(251,078)	$	(411,705)

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

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 (Deficit)
	Shares	Amount
Balances, December 31, 2020	114,742,304	$	1,147	$	1,827,914	$	200,697	$	(13,598)	$	2,016,160
Net loss	—	—		—		(251,269)		—		(251,269)
Other comprehensive income	—	—		—		—		191		191
Cash dividends declared, $0.01 per share	—	—		—		(1,147)		—		(1,147)


Stock-based compensation expense	—	—		5,737		—		—		5,737


Balances, March 31, 2021	114,742,304	$	1,147	$	1,833,651	$	(51,719)	$	(13,407)	$	1,769,672


				Additional Paid-in Capital				Accumulated Other Comprehensive Loss		Total Stockholders’ Equity
	Common Stock					Retained Earnings
	Shares	Amount
Balances, December 31, 2019	112,987,952	$	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 withholdings	730	—		(3)		—		—		(3)
Stock-based compensation expense	—	—		5,561		—		—		5,561


Balances, March 31, 2020	112,988,682	$	1,130	$	1,797,154	$	554,562	$	(11,129)	$	2,341,717

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)


	For the Three Months Ended March 31,
	2021		2020
Cash flows from operating activities:
Net loss	$	(251,269)	$	(411,895)
Adjustments to reconcile net loss to net cash provided by operating activities:

Depletion, depreciation, amortization, and asset retirement obligation liability accretion	166,960		233,489
Impairment	8,750		989,763
Stock-based compensation expense	5,737		5,561
Net derivative (gain) loss	344,689		(545,340)
Derivative settlement gain (loss)	(107,885)		73,437
Amortization of debt discount and deferred financing costs	4,723		3,992
Gain on extinguishment of debt	—		(12,195)
Deferred income taxes	(52)		(99,347)
Other, net	(14,592)		(816)
Net change in working capital	(51,437)		(18,517)





Net cash provided by operating activities	105,624		218,132

Cash flows from investing activities:

Capital expenditures	(147,563)		(139,306)

Other	(71)		—
Net cash used in investing activities	(147,634)		(139,306)

Cash flows from financing activities:
Proceeds from revolving credit facility	440,000		425,500
Repayment of revolving credit facility	(398,000)		(476,000)


Cash paid to repurchase Senior Notes	—		(28,318)


Other	—		(3)
Net cash provided by (used in) financing activities	42,000		(78,821)

Net change in cash, cash equivalents, and restricted cash	(10)		5
Cash, cash equivalents, and restricted cash at beginning of period	10		10
Cash, cash equivalents, and restricted cash at end of period	$	—	$	15

Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest	$	(53,449)	$	(47,469)

Investing activities:
Increase in capital expenditure accruals and other	$	37,409	$	16,802

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

SM ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

Description of Operations

SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of 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 2020 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, 2021, 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 2020 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 2020 Form 10-K.

Recently Issued Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021, to provide clarifying guidance regarding the scope of Topic 848. 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 and ASU 2021-01 are effective for all entities through December 31, 2022. As of March 31, 2021, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. 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.

There are no other 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, 2021, or through the filing of this report.

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 areas for the three months ended March 31, 2021, and 2020:


	Midland Basin						South Texas						Total
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
	2021			2020			2021			2020			2021			2020
	(in thousands)
Oil production revenue	$	286,105		$	276,136		$	19,672		$	15,557		$	305,777		$	291,693
Gas production revenue	57,806			11,334			31,852			29,376			89,658			40,710
NGL production revenue	100			58			27,630			21,772			27,730			21,830
Total	$	344,011		$	287,528		$	79,154		$	66,705		$	423,165		$	354,233
Relative percentage	81		%	81		%	19		%	19		%	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 2020 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, therefore there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of 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, 2021, and December 31, 2020, were $152.1 million and $108.9 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 - Equity

On June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its then outstanding common stock, at an exercise price of $0.01 per share.

The fair value of the warrants on the issuance date was determined using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). The Company evaluated the warrants under authoritative accounting guidance and determined that they should be classified as equity instruments. Upon issuance, the warrants were recorded in additional paid-in capital on the accompanying balance sheets at a fair value of $21.5 million, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the warrants since issuance.

The Warrant Agreement dated as of June 17, 2020 (“Warrant Agreement”), states that the warrants are exercisable any time from and after the Triggering Date, as subsequently defined, until June 30, 2023. The Triggering Date is defined by the Warrant Agreement as the first trading day following five consecutive trading days on which the product of the number of shares of common stock issued and outstanding on four of the five trading days multiplied by the closing price per share of common stock for each such trading day exceeds $1.0 billion (“Triggering Date”). The warrants issued are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement, if exercised. The Triggering Date occurred on January 14, 2021, and the warrants became exercisable at the election of the holders. The warrants may be exercised either in full or from time to time in part, until their expiration on June 30, 2023.

Subsequent to March 31, 2021, the Company issued 3,083,403 shares of unregistered, restricted common stock as a result of the cashless exercise of 3,086,147 warrants at a weighted-average share price of $11.36 per share, as determined under the terms of the Warrant Agreement. No underwriters were involved in the sales, and the securities bear restrictive legends restricting transfer of the securities without registration under the Securities Act or an applicable exemption from registration.

Note 4 - Income Taxes

The provision for income taxes for the three months ended March 31, 2021, and 2020, consisted of the following:


	For the Three Months Ended March 31,
		2021			2020
		(in thousands)
Current portion of income tax (expense) benefit:
Federal		$	—		$	—
State		(158)			(339)
Deferred portion of income tax benefit		52			99,347
Income tax (expense) benefit		$	(106)		$	99,008

Effective tax rate		—		%	19.4		%

Recorded income tax expense or benefit differs from the amount 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, the cumulative impact of other smaller permanent differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balance. 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.

For all years before 2017, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

Note 5 - Long-Term Debt

The following table summarizes the Company’s total outstanding balance on its revolving credit facility, Senior Secured Notes net of unamortized discount and deferred financing costs, and Senior Unsecured Notes, net of unamortized deferred financing costs, as of March 31, 2021, and December 31, 2020:


	As of March 31, 2021		As of December 31, 2020
	(in thousands)
Revolving credit facility	$	135,000	$	93,000
Senior Secured Notes (1)	464,222		460,656
Senior Unsecured Notes (1)	1,661,429		1,660,663
Total	$	2,260,651	$	2,214,319

____________________________________________

(1) Senior Secured Notes and Senior Unsecured Notes are defined below.

Credit Agreement

The Company’s Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion. As of March 31, 2021, the borrowing base and aggregate lender commitments under the Credit Agreement were $1.1 billion. The next scheduled borrowing base redetermination date is October 1, 2021.

The Credit Agreement is scheduled to mature on September 28, 2023. The maturity date could, however, occur earlier on August 16, 2022, if the Company has not completed certain repurchase, redemption, or refinancing activities associated with its 6.125% Senior Notes due 2022 (“2022 Senior Notes”), and does not have certain unused availability for borrowing under the Credit Agreement, as outlined in the Credit Agreement.

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 as presented in Note 5 - Long-Term Debt in the 2020 Form 10-K. 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.

The Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the Company. Please refer to Note 1 - Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04, which provides guidance related to reference rate reform.

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of April 21, 2021, March 31, 2021, and December 31, 2020:


	As of April 21, 2021		As of March 31, 2021		As of December 31, 2020
	(in thousands)
Revolving credit facility (1)	$	76,500	$	135,000	$	93,000
Letters of credit (2)	—		—		42,000
Available borrowing capacity	1,023,500		965,000		965,000
Total aggregate lender commitment amount	$	1,100,000	$	1,100,000	$	1,100,000

____________________________________________

(1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $3.9 million and $4.3 million as of March 31, 2021, and December 31, 2020, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis.

(2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.

Senior Notes

Senior Secured Notes. Senior Secured Notes, net of unamortized discount and deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of March 31, 2021, and December 31, 2020, consisted of the following:


	As of March 31, 2021
	Principal Amount		Unamortized Debt Discount		Unamortized Deferred Financing Costs		Net
	(in thousands)
1.50% Senior Secured Convertible Notes due 2021	$	65,485	$	914	$	87	$	64,484
10.0% Senior Secured Notes due 2025	446,675		36,085		10,852		399,738
Total	$	512,160	$	36,999	$	10,939	$	464,222

	As of December 31, 2020
	Principal Amount		Unamortized Debt Discount		Unamortized Deferred Financing Costs		Net
	(in thousands)
1.50% Senior Secured Convertible Notes due 2021	$	65,485	$	1,828	$	175	$	63,482
10.0% Senior Secured Notes due 2025	446,675		37,943		11,558		397,174
Total	$	512,160	$	39,771	$	11,733	$	460,656

The 1.50% Senior Secured Convertible Notes due 2021 (“2021 Senior Secured Convertible Notes”) and the 10.0% Senior Secured Notes due 2025 (“2025 Senior Secured Notes,” and together with the 2021 Senior Secured Convertible Notes, the “Senior Secured Notes”) are senior obligations of the Company, secured on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement and equal in priority to one another. The Senior Secured Notes rank senior in right of payment with all of the Company’s existing and any future unsecured senior or subordinated debt.

Beginning January 1, 2021, until the maturity date, holders may convert their 2021 Senior Secured Convertible Notes at any time based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the 2021 Senior Secured Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment. The if-converted value of the 2021 Senior Secured Convertible Notes did not exceed the principal amount as of March 31, 2021, or through the filing of this report. The Company has elected to settle the 2021 Senior Secured Convertible Notes obligation, due July 1, 2021, in cash and intends to settle the obligation using borrowings under its revolving credit facility. The remaining debt discount and debt-related issuance costs are being amortized to the principal value of the 2021 Senior Secured Convertible Notes as interest expense through the maturity date. Interest expense recognized on the 2021 Senior Secured Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $1.2 million and $2.9 million for the three months ended March 31, 2021, and 2020, respectively. The Company may not redeem the 2021 Senior Secured Convertible Notes prior to the maturity date.

The Company may redeem some or all of its 2025 Senior Secured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indenture governing the 2025 Senior Secured Notes.

Please refer to Note 5 - Long-Term Debt in the 2020 Form 10-K for additional detail on the Company’s Senior Secured Notes and capped call transactions associated with the 2021 Senior Secured Convertible Notes.

Senior Unsecured Notes. Senior Unsecured Notes, net of unamortized deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of March 31, 2021, and December 31, 2020, consisted of the following:


	As of March 31, 2021						As of December 31, 2020
	Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net
	(in thousands)
6.125% Senior Notes due 2022	$	212,403	$	743	$	211,660	$	212,403	$	855	$	211,548
5.0% Senior Notes due 2024	277,034		1,448		275,586		277,034		1,576		275,458
5.625% Senior Notes due 2025	349,118		2,634		346,484		349,118		2,792		346,326
6.75% Senior Notes due 2026	419,235		3,795		415,440		419,235		3,970		415,265
6.625% Senior Notes due 2027	416,791		4,532		412,259		416,791		4,725		412,066
Total	$	1,674,581	$	13,152	$	1,661,429	$	1,674,581	$	13,918	$	1,660,663

The senior unsecured notes listed above (collectively referred to as “Senior Unsecured Notes,” and together with the Senior Secured Notes, “Senior Notes”) are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company may redeem some or all of its Senior Unsecured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Unsecured Notes.

During the three months ended March 31, 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 settlement.

Please refer to Note 5 - Long-Term Debt in the 2020 Form 10-K for additional detail on the Company’s Senior Unsecured Notes.

Covenants

The Company is subject to certain financial and non-financial covenants under the Credit Agreement and the indentures governing the Senior Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted payments including dividends, sell assets, with respect to the Company’s restricted subsidiaries, permit the consensual restriction on the ability of such restricted subsidiaries to pay dividends or indebtedness owing to the Company or to any other restricted subsidiaries, create liens that secure debt, enter into transactions with affiliates, and merge or consolidate with another company. The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of March 31, 2021, and through the filing of this report.

Please refer to Note 5 - Long-Term Debt in the 2020 Form 10-K for additional detail on the Company’s covenants under the Credit Agreement and indentures governing the Senior Notes.

Capitalized Interest

Capitalized interest costs totaled $4.3 million and $2.7 million for the three months ended March 31, 2021, and 2020, 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 2020 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the 2020 Form 10-K for additional discussion of the Company’s commitments.

Drilling Rig Service Contracts. During the three months ended March 31, 2021, the Company amended certain of its drilling rig contracts resulting in the extension of contract terms. As of March 31, 2021, the Company’s drilling rig commitments totaled

$23.5 million under contract terms extending through the second quarter of 2022. If all of these contracts were terminated as of March 31, 2021, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $14.0 million in early termination fees. No material expenses related to early termination or standby fees were incurred by the Company during the three months ended March 31, 2021, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during the remainder of 2021.

Drilling and Completion Commitments. During the three months ended March 31, 2021, the Company amended an agreement that included minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2022, the Company will be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of March 31, 2021, the liquidated damages could range from zero to a maximum of $51.3 million, with the maximum exposure assuming no additional development activity occurred prior to March 31, 2022. 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, 2021, 3.8 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”).

Performance Share Units

The Company generally 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 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 2018 and 2019, the settlement criteria include a combination of the Company’s Total Shareholder Return (“TSR”) relative to the TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance criteria, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair values of the PSUs granted in 2018 and 2019 were 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 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. No PSUs were granted in 2020.

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 $3.2 million and $2.6 million for the three months ended March 31, 2021, and 2020, respectively. As of March 31, 2021, there was $4.5 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2022. There were no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2021.

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 the applicable vesting period or upon other triggering events as set forth in the Equity Plan.

The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the 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 $2.2 million and $2.6 million for the three months ended March 31, 2021, and 2020, respectively. As of March 31, 2021, there was $12.5 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2023. There were no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2021.

Please refer to Note 7 - Compensation Plans in the 2020 Form 10-K for additional detail on the Company’s Equity Plan.

Note 8 - Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:

•Level 1 – quoted prices in active markets for identical assets or liabilities

•Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

•Level 3 – significant inputs to the valuation model are unobservable.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of March 31, 2021:


	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives (1)	$	—	$	34,426	$	—

Liabilities:
Derivatives (1)	$	—	$	439,397	$	—

__________________________________________

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


	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives (1)	$	—	$	54,353	$	—
Liabilities:
Derivatives (1)	$	—	$	222,520	$	—

____________________________________________

(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 2020 Form 10-K for more information regarding the Company’s derivative instruments.

Oil and Gas Properties and Other Property and Equipment

The Company had no assets included in total property and equipment, net, measured at fair value as of March 31, 2021, or December 31, 2020.

No proved property impairment expense was recorded during the three months ended March 31, 2021. For the three months ended March 31, 2020, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities 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 used a discount rate of 11 percent in its calculation of the present value of expected future net cash flows based on the prevailing market-based weighted average cost of capital as of March 31, 2020.

For the three months ended March 31, 2021, and 2020, the Company recorded impairment expense related to the abandonment and impairment of unproved properties of $8.8 million, and $33.1 million, respectively. 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, 2021, and December 31, 2020, are recorded at carrying value.

Please refer to Note 1 - Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the 2020 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 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, 2021, or December 31, 2020, 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, 2021				As of December 31, 2020
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(in thousands)
1.50% Senior Secured Convertible Notes due 2021	$	65,485	$	63,864	$	65,485	$	61,449
10.0% Senior Secured Notes due 2025	$	446,675	$	502,858	$	446,675	$	482,887
6.125% Senior Unsecured Notes due 2022	$	212,403	$	209,633	$	212,403	$	205,379
5.0% Senior Unsecured Notes due 2024	$	277,034	$	261,936	$	277,034	$	240,072
5.625% Senior Unsecured Notes due 2025	$	349,118	$	323,007	$	349,118	$	289,401
6.75% Senior Unsecured Notes due 2026	$	419,235	$	387,373	$	419,235	$	342,385
6.625% Senior Unsecured Notes due 2027	$	416,791	$	384,323	$	416,791	$	331,220

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 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.

As of March 31, 2021, potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and warrants, which were measured using the treasury stock method. The warrants became exercisable at the election of the holders on January 14, 2021, and as a result, they were included as potentially dilutive securities beginning January 1, 2021. Please refer to Note 3 - Equity and Note 7 - Compensation Plans in this report, and Note 9 - Earnings Per Share in the 2020 Form 10-K for additional detail on these potentially dilutive securities.

As of March 31, 2020, potentially dilutive securities for this calculation consisted primarily of non-vested RSUs, contingent PSUs, and shares into which the 2021 Senior Convertible Notes were convertible, which were measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price applicable to the 2021 Senior Convertible Notes for the three months ended March 31, 2020, therefore, the 2021 Senior Convertible Notes had no dilutive impact. The Company has elected to satisfy any conversion obligation with respect to the 2021 Senior Convertible Notes solely in cash. As a result, the Company’s 2021 Senior Secured Convertible Notes are no longer convertible into shares of the Company’s common stock and thus, were not considered to be a potentially dilutive instrument as of March 31, 2021.

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 number of anti-dilutive securities for the periods presented:


	For the Three Months Ended March 31,
		2021	2020
		(in thousands)
Anti-dilutive		8,106	1,219

The following table sets forth the calculations of basic and diluted net loss per common share:


	For the Three Months Ended March 31,
		2021		2020
		(in thousands, except per share data)
Net loss		$	(251,269)	$	(411,895)

Basic weighted-average common shares outstanding		114,759		113,009
Dilutive effect of non-vested RSUs and contingent PSUs		—		—
Dilutive effect of warrants		—		—
Diluted weighted-average common shares outstanding		114,759		113,009

Basic net loss per common share		$	(2.19)	$	(3.64)
Diluted net loss per common share		$	(2.19)	$	(3.64)

Note 10 - Derivative Financial Instruments

Summary of Oil, Gas, and NGL Derivative Contracts in Place

The Company regularly enters into 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, 2021, 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 NGL production, and swap arrangements for gas production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

The Company has entered into fixed price oil 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 NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices, NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices, and between NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“MEH”) for a portion of its South Texas oil production with sales contracts that settle at Argus WTI Houston MEH prices. The Company has also entered into crude oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.

As of March 31, 2021, the Company had commodity derivative contracts outstanding through the fourth quarter of 2023 as summarized in the tables below.

Oil Swaps


Contract Period	NYMEX WTI Volumes	Weighted-Average Contract Price
	(MBbl)	(per Bbl)
Second quarter 2021	5,508	$	40.88
Third quarter 2021	5,363	$	41.16
Fourth quarter 2021	4,744	$	39.85
2022	7,823	$	44.69
2023	1,190	$	45.20
Total	24,628

Oil Collars


Contract Period	NYMEX WTI Volumes	Weighted-Average Floor Price		Weighted-Average Ceiling Price
	(MBbl)	(per Bbl)		(per Bbl)



2022	1,224	$	50.00	$	54.89

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)		WTI Houston MEH-NYMEX WTI Volumes	Weighted-Average Contract Price (3)
	(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)
Second quarter 2021	4,172	$	0.81	910	$	(7.86)	493	$	0.60
Third quarter 2021	3,756	$	0.75	920	$	(7.86)	356	$	0.60
Fourth quarter 2021	3,824	$	0.71	920	$	(7.86)	466	$	0.60
2022	9,500	$	1.15	3,650	$	(7.78)	1,329	$	1.25


Total	21,252			6,400			2,644

____________________________________________

(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).

(3) Represents the price differential between Argus WTI Houston MEH (Houston, Texas) and NYMEX WTI (Cushing, Oklahoma).

Oil Roll Differential Swaps


Contract Period	NYMEX WTI Volumes	Weighted-Average Contract Price
	(MBbl)	(per Bbl)
Second quarter 2021	4,743	$	(0.16)
Third quarter 2021	4,326	$	(0.18)
Fourth quarter 2021	3,831	$	(0.16)
2022	11,278	$	0.11
Total	24,178

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 2021	13,672	$	2.45	7,230	$	1.76
Third quarter 2021	12,575	$	2.40	8,086	$	1.88
Fourth quarter 2021	12,412	$	2.41	7,627	$	1.82
2022	28,932	$	2.52	13,716	$	2.30

Total (1)	67,591			36,659

____________________________________________

(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, 2021, WAHA volumes were comprised of 65 percent IF WAHA and 35 percent GD WAHA.

NGL Swaps


	OPIS Propane Mont Belvieu Non-TET		OPIS Normal Butane Mont Belvieu Non-TET
Contract Period		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price
		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)
Second quarter 2021		818	$	22.14	37	$	30.87
Third quarter 2021		854	$	22.16	37	$	30.87
Fourth quarter 2021		824	$	22.15	36	$	30.87
2022		231	$	22.99	—	$	—

Total		2,727			110

NGL Collars


Contract Period	OPIS Propane Mont Belvieu Non-TET	Weighted-Average Floor Price		Weighted-Average Ceiling Price
	(MBbl)	(per Bbl)		(per Bbl)



2022	234	$	22.05	$	27.30

Commodity Derivative Contracts Entered Into Subsequent to March 31, 2021

Subsequent to March 31, 2021, the Company entered into a NYMEX WTI costless collar contract for the first quarter of 2022 for a total of 180 MBbl of oil production with a contract floor price of $50.00 per Bbl and a contract ceiling price of $65.00 per Bbl.

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. The fair value of the commodity derivative contracts was a net liability of $405.0 million and $168.2 million as of March 31, 2021, and December 31, 2020, respectively.

The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:


	As of March 31, 2021		As of December 31, 2020
	(in thousands)
Derivative assets:
Current assets	$	20,859	$	31,203
Noncurrent assets	13,567		23,150
Total derivative assets	$	34,426	$	54,353
Derivative liabilities:
Current liabilities	$	371,802	$	200,189
Noncurrent liabilities	67,595		22,331
Total derivative liabilities	$	439,397	$	222,520

Offsetting of Derivative Assets and Liabilities

As of March 31, 2021, and December 31, 2020, 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, 2021		December 31, 2020		March 31, 2021		December 31, 2020
	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	34,426	$	54,353	$	(439,397)	$	(222,520)
Amounts not offset in the accompanying balance sheets	(34,238)		(53,598)		34,238		53,598
Net amounts	$	188	$	755	$	(405,159)	$	(168,922)

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,
		2021		2020
		(in thousands)
Derivative settlement (gain) loss:
Oil contracts		$	56,329	$	(53,582)
Gas contracts		40,448		(14,625)
NGL contracts		11,108		(5,230)
Total net derivative settlement (gain) loss		$	107,885	$	(73,437)

Net derivative (gain) loss:
Oil contracts		$	265,815	$	(542,540)
Gas contracts		48,922		6,728
NGL contracts		29,952		(9,528)
Total net derivative (gain) loss		$	344,689	$	(545,340)

Credit Related Contingent Features

As of March 31, 2021, 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.

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 domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our vision is to be a premier operator of top tier assets and to sustainably grow value for all of our stakeholders. This includes short-term operational and financial goals of generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term goal is to deliver cash flow growth that is supported by our high-quality asset base and ability to generate favorable returns. Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.

We are 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. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s environmental, social and governance policies, programs and initiatives, and reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations, compensation for our executives and employees under our short-term and long-term incentive plans is calculated based on certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures.

Areas of Operations

Our Midland Basin assets are comprised of approximately 80,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the first quarter of 2021, drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continued to focus primarily on delineating, developing, and expanding 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 155,000 net acres located in the Maverick Basin in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on production from the Eagle Ford shale formation and further delineation and development of 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. 2021 capital activity in South Texas has been, and will continue to be, concentrated on the Austin Chalk formation given the higher liquids content of production and favorable economics.

First Quarter 2021 Overview and Outlook for the Remainder of 2021

Over a period of several days in February 2021, the state of Texas was impacted by a significant weather event that resulted in abnormally low temperatures, freezing conditions, and widespread power outages (“Texas Weather Event”). During this time, we experienced interruptions to third-party power supply and third-party gas gathering that led to well shut-ins at our Midland Basin and South Texas assets, which resulted in reduced production for approximately 14 days. Our supply chain was also impacted, causing significant delays in delivery of materials and technological services necessary to resume drilling and completion activities, which in turn resulted in delays in bringing new wells online, further impacting first quarter production. The oil and gas production industry in Texas experienced significant interruptions to production while demand for energy in Texas significantly increased due to cold temperatures. The lack of supply and increase in demand for energy during this period caused a temporary spike in gas prices. While the comprehensive impacts of the Texas Weather Event are not expected to have a material impact on our full year 2021 business operations, financial position, or operating results, this event temporarily impacted our total production volumes; oil, gas, and NGL production revenue; other operating income; oil, gas, and NGL production expense; and net derivative (gain) loss for the three months ended March 31, 2021. Please refer to A 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, 2021, and December 31, 2020, and Between the Three Months Ended March 31, 2021, and 2020 below for additional discussion.

The Pandemic remains a global health crisis and continues to cause turmoil and uncertainty in financial and commodity markets. Notwithstanding the deployment of vaccinations to prevent the spread of the COVID-19 virus, stability in the markets and demand for the commodities produced by our industry have not returned to pre-Pandemic levels, and likely will not for some time. The impacts of the Pandemic continue to be unpredictable, and given the dynamic nature of the Pandemic, we are unable to reasonably

estimate the period of time that the related market conditions will exist or the extent to which they will continue to impact our business, results of operations, and financial condition, or the timing of any further recovery. Commodity prices have improved from historic lows in 2020, however, future case surges or outbreaks could have further negative impacts, and as a result, may require us to adjust our business plan. For additional detail, please refer to the Risk Factors section in Part I, Item 1A of our 2020 Form 10-K. Despite continuing negative impacts of the Pandemic and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top tier Midland Basin and South Texas assets.

The safety of our employees, contractors, and the communities where we work remains our first priority as we continue to operate during the Pandemic. While our core business operations require certain individuals to be physically present at well site locations, substantially all of our office-based employees have continued working remotely in order to limit physical interactions and to mitigate the spread of COVID-19, and will continue to do so well into 2021. For individuals who are unable to perform their jobs remotely, we maintain and continually assess procedures designed to limit the spread of COVID-19, including social distancing and enhanced sanitization measures, and we continue to communicate to and train all of our employees regarding best practices for maintaining a healthy and safe work environment. We believe that we meet or exceed Centers for Disease Control and Prevention and federal Occupational Safety and Health Act guidelines related to the prevention of the transmission of COVID-19. Since these measures were initially implemented in the first quarter of 2020, we have continued to operate without significant disruptions to our business operations. Our pre-existing control environment and internal controls continue to be effective and we continue to address new risks directly related to the Pandemic as we identify them.

We entered 2021 with a total capital program budget between $650.0 million and $675.0 million. Our financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our 2021 capital program remains focused on highly economic oil development projects in both our Midland Basin assets and South Texas assets. We believe our assets provide strong returns and are capable of providing for growth of internally generated cash flows while allowing for flexibility of production levels, which aligns with our priorities of improving leverage metrics and maintaining strong financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund our 2021 capital program.

Financial and Operational Results. Average net daily equivalent production for the three months ended March 31, 2021, was 111.6 MBOE which was a decrease of nine percent and 18 percent compared with the three months ended December 31, 2020, and March 31, 2020, respectively. These decreases were primarily driven by lower capital expenditures in late 2020 and the first quarter of 2021 and the Texas Weather Event discussed above.

Strengthening commodity prices and the supply and demand imbalance caused by the Texas Weather Event resulted in increases in realized prices before the effects of derivative settlements for oil, gas, and NGLs of 39 percent, 69 percent, and 46 percent, respectively, for the three months ended March 31, 2021, compared with the three months ended December 31, 2020, and increases of 23 percent, 170 percent, and 98 percent, respectively, for the three months ended March 31, 2021, compared with the same period in 2020. These increases resulted in oil, gas, and NGL production revenue of $423.2 million for the three months ended March 31, 2021, compared with $320.2 million and $354.2 million for the three months ended December 31, 2020, and March 31, 2020, respectively, which was a sequential quarterly increase of 32 percent and a year-over-year increase of 19 percent. Total production costs on a per BOE basis for the three months ended March 31, 2021, were $10.04 per BOE, which was an 18 percent increase from $8.52 per BOE for the three months ended December 31, 2020, and a four percent increase from $9.67 per BOE for the same period in 2020.

We recorded net derivative losses of $344.7 million and $152.7 million for the three months ended March 31, 2021, and December 31, 2020, respectively, and a net derivative gain of $545.3 million for the three months ended March 31, 2020. Included within these derivative amounts is a loss of $107.9 million on derivative contracts that settled during the three months ended March 31, 2021, and gains of $65.0 million and $73.4 million for the three months ended December 31, 2020, and March 31, 2020, respectively. The loss during the three months ended March 31, 2021, was primarily due to increased commodity prices.

Please refer to A 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, 2021, and December 31, 2020, and Between the Three Months Ended March 31, 2021, and 2020 below for additional discussion.

Financial and operational activities during the three months ended March 31, 2021, resulted in the following:

•net cash provided by operating activities of $105.6 million for the three months ended March 31, 2021, compared with $218.1 million for the three months ended March 31, 2020. Please refer to Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2021, and 2020 below for additional discussion;

•net loss of $251.3 million, or $2.19 per diluted share, for the three months ended March 31, 2021, compared with a net loss of $165.2 million, or $1.44 per diluted share, for the three months ended December 31, 2020, and a net loss of $411.9 million, or $3.64 per diluted share, for the three months ended March 31, 2020. The net loss for the three months ended March 31, 2021, was primarily due to a $236.8 million downward mark-to-market adjustment on our commodity derivative contracts. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended

March 31, 2021, and December 31, 2020, and Between the Three Months Ended March 31, 2021, and 2020 below for additional discussion regarding the components of net loss for the periods presented; and

•adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2021, was $215.0 million, compared with $286.0 million for the three months ended March 31, 2020. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations of net loss and net cash provided by operating activities.

Operational Activities. In our Midland Basin program, we operated three drilling rigs and three completion crews during the first quarter of 2021. We drilled 16 gross (13 net) wells and completed 16 gross (14 net) wells during the first quarter of 2021, and production volumes decreased year-over-year by 10 percent to 6.9 MMBOE. Costs incurred in our Midland Basin program during the three months ended March 31, 2021, totaled $138.2 million, or 72 percent of our total costs incurred for the period. We anticipate averaging three drilling rigs and between one and two completion crews during 2021. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on delineating and developing the Spraberry and Wolfcamp formations.

In our South Texas program, we operated two drilling rigs and one completion crew during the first quarter of 2021. We drilled five gross (five net) wells and completed six gross (three net) wells during the first quarter of 2021, and production volumes decreased year-over-year by 33 percent to 3.2 MMBOE. Costs incurred in our South Texas program during the three months ended March 31, 2021, totaled $44.9 million, or 23 percent of our total costs incurred for the period. We anticipate operating between one and two drilling rigs and one completion crew during 2021. Drilling and completion activities in South Texas during the remainder of 2021 will be focused on delineating and developing the Austin Chalk formation.

The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three months ended March 31, 2021:


	Midland Basin		South Texas		Total
	Gross	Net	Gross	Net	Gross	Net
Wells drilled but not completed at December 31, 2020	66	58	31	28	97	86
Wells drilled	16	13	5	5	21	18
Wells completed	(16)	(14)	(6)	(3)	(22)	(17)
Other (1)	—	1	—	—	—	1
Wells drilled but not completed at March 31, 2021 (2)	66	58	30	30	96	88

____________________________________________

(1) Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells. Working interest changes can result from divestitures, joint development agreements, farmouts, and other activities.

(2) The South Texas drilled but not completed well count as of March 31, 2021, includes 13 gross (13 net) wells that are not included in our five-year development plan, 12 of which are in the Eagle Ford shale.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $192.5 million for the three months ended March 31, 2021, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.

Production Results. The table below presents our production by product type for each of our areas of operation for the three months ended March 31, 2021, December 31, 2020, and March 31, 2020:


	Three Months Ended March 31,
	March 31, 2021		December 31, 2020		March 31, 2020
Midland Basin Production:
Oil (MMBbl)	5.1		5.3		5.9
Gas (Bcf)	10.6		12.6		9.9
NGLs (MMBbl)	—		—		—
Equivalent (MMBOE)	6.9		7.5		7.6
Average net daily equivalent (MBOE per day)	76.1		81.0		83.4
Relative percentage	68	%	66	%	61	%

South Texas Production:
Oil (MMBbl)	0.3		0.4		0.4
Gas (Bcf)	11.0		12.7		16.6
NGLs (MMBbl)	1.0		1.2		1.6
Equivalent (MMBOE)	3.2		3.8		4.8
Average net daily equivalent (MBOE per day)	35.5		41.4		52.5
Relative percentage	32	%	34	%	39	%

Total Production:
Oil (MMBbl)	5.4		5.8		6.3
Gas (Bcf)	21.5		25.3		26.5
NGLs (MMBbl)	1.0		1.3		1.6
Equivalent (MMBOE)	10.0		11.3		12.4
Average net daily equivalent (MBOE per day)	111.6		122.4		135.9

____________________________________________

Note: Amounts may not calculate due to rounding.

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, and transportation differentials and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the first quarter of 2021 as well as the fourth and first quarters of 2020:


	For the Three Months Ended
	March 31, 2021		December 31, 2020		March 31, 2020
Oil (per Bbl):
Average NYMEX contract monthly price	$	57.84	$	42.66	$	46.17
Realized price, before the effect of derivative settlements	$	56.33	$	40.54	$	45.96
Effect of oil derivative settlements	$	(10.38)	$	12.17	$	8.44
Gas:
Average NYMEX monthly settle price (per MMBtu)	$	2.69	$	2.66	$	1.95
Realized price, before the effect of derivative settlements (per Mcf)	$	4.16	$	2.46	$	1.54
Effect of gas derivative settlements (per Mcf)	$	(1.88)	$	(0.18)	$	0.55
NGLs (per Bbl):
Average OPIS price (1)	$	30.47	$	21.68	$	17.02
Realized price, before the effect of derivative settlements	$	26.93	$	18.43	$	13.62
Effect of NGL derivative settlements	$	(10.79)	$	(0.63)	$	3.27

____________________________________________

(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.

Given the dynamic nature of the Pandemic, we expect future benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing of any further recovery or future infection rate surges or outbreaks. 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 2021 Overview and Outlook for the Remainder of 2021 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 as of April 21, 2021, and March 31, 2021:


	As of April 21, 2021		As of March 31, 2021
NYMEX WTI oil (per Bbl)	$	59.79	$	57.79
NYMEX Henry Hub gas (per MMBtu)	$	2.90	$	2.79
OPIS NGLs (per Bbl)	$	26.91	$	28.09

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 commodity derivative contracts are overseen by a financial risk management committee consisting of certain of our senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on 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 commodity derivative contracts. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil 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.

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, 2021, and the preceding three quarters.


	For the Three Months Ended
	March 31,		December 31,		September 30,		June 30,
	2021		2020		2020		2020
	(in millions)
Production (MMBOE)	10.0		11.3		11.6		11.2
Oil, gas, and NGL production revenue	$	423.2	$	320.2	$	282.0	$	169.8
Oil, gas, and NGL production expense	$	100.9	$	96.0	$	95.3	$	80.4
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	167.0	$	188.9	$	181.7	$	180.9
Exploration	$	9.3	$	11.3	$	8.5	$	9.8
General and administrative	$	24.7	$	20.0	$	24.5	$	27.2
Net loss	$	(251.3)	$	(165.2)	$	(98.3)	$	(89.3)

____________________________________________

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics


	For the Three Months Ended
	March 31,			December 31,			September 30,			June 30,
	2021			2020			2020			2020
Average net daily equivalent production (MBOE per day)	111.6			122.4			126.3			122.9
Lease operating expense (per BOE)	$	4.64		$	4.10		$	3.65		$	3.30
Transportation costs (per BOE)	$	2.94		$	2.89		$	3.11		$	3.12
Production taxes as a percent of oil, gas, and NGL production revenue	4.6		%	4.0		%	4.3		%	3.7		%
Ad valorem tax expense (per BOE)	$	0.52		$	0.38		$	0.40		$	0.22
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	16.62		$	16.77		$	15.64		$	16.17
General and administrative (per BOE)	$	2.46		$	1.78		$	2.10		$	2.43

____________________________________________

Note: Amounts may not calculate due to rounding.

A Three Month Overview of Selected Production and Financial Information, Including Trends


		For the Three Months Ended								Amount Change Between the Three Months Ended						Percent Change Between the Three Months Ended
	March 31, 2021		December 31, 2020			March 31, 2020			March 31, 2021 & December 31, 2020			March 31, 2021 & 2020			March 31, 2021 & December 31, 2020			March 31, 2021 & 2020
Net production volumes: (1)
Oil (MMBbl)				5.4			5.8			6.3			(0.4)			(0.9)			(6)	%	(14)	%
Gas (Bcf)				21.5			25.3			26.5			(3.8)			(5.0)			(15)	%	(19)	%
NGLs (MMBbl)				1.0			1.3			1.6			(0.2)			(0.6)			(18)	%	(36)	%
Equivalent (MMBOE)				10.0			11.3			12.4			(1.2)			(2.3)			(11)	%	(19)	%
Average net daily production: (1)
Oil (MBbl per day)				60.3			62.9			69.8			(2.6)			(9.4)			(4)	%	(14)	%
Gas (MMcf per day)				239.4			275.3			291.2			(35.9)			(51.9)			(13)	%	(18)	%
NGLs (MBbl per day)				11.4			13.6			17.6			(2.2)			(6.2)			(16)	%	(35)	%
Equivalent (MBOE per day)				111.6			122.4			135.9			(10.8)			(24.2)			(9)	%	(18)	%
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue				$	305.8		$	234.8		$	291.7		$	71.0		$	14.1		30	%	5	%
Gas production revenue				89.7			62.3			40.7			27.3			48.9			44	%	120	%
NGL production revenue				27.7			23.1			21.8			4.6			5.9			20	%	27	%
Total oil, gas, and NGL production revenue				$	423.2		$	320.2		$	354.2		$	103.0		$	68.9		32	%	19	%
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense				$	46.7		$	46.2		$	58.8		$	0.5		$	(12.1)		1	%	(21)	%
Transportation costs				29.6			32.6			38.4			(3.0)			(8.9)			(9)	%	(23)	%
Production taxes				19.5			12.9			14.9			6.6			4.6			51	%	31	%
Ad valorem tax expense				5.2			4.3			7.4			0.9			(2.2)			21	%	(30)	%
Total oil, gas, and NGL production expense				$	100.9		$	96.0		$	119.6		$	5.0		$	(18.6)		5	%	(16)	%
Realized price, before the effect of derivative settlements:
Oil (per Bbl)				$	56.33		$	40.54		$	45.96		$	15.79		$	10.37		39	%	23	%
Gas (per Mcf)				$	4.16		$	2.46		$	1.54		$	1.70		$	2.62		69	%	170	%
NGLs (per Bbl)				$	26.93		$	18.43		$	13.62		$	8.50		$	13.31		46	%	98	%
Per BOE				$	42.11		$	28.42		$	28.64		$	13.69		$	13.47		48	%	47	%
Per BOE data: (1)
Production costs:
Lease operating expense				$	4.64		$	4.10		$	4.75		$	0.54		$	(0.11)		13	%	(2)	%
Transportation costs				2.94			2.89			3.11			0.05			(0.17)			2	%	(5)	%
Production taxes				1.94			1.15			1.20			0.79			0.74			69	%	62	%
Ad valorem tax expense				0.52			0.38			0.60			0.14			(0.08)			37	%	(13)	%
Total production costs (1)				$	10.04		$	8.52		$	9.67		$	1.52		$	0.37		18	%	4	%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion				$	16.62		$	16.77		$	18.88		$	(0.15)		$	(2.26)		(1)	%	(12)	%
General and administrative				$	2.46		$	1.78		$	2.22		$	0.68		$	0.24		38	%	11	%
Derivative settlement gain (loss) (2)				$	(10.74)		$	5.77		$	5.94		$	(16.51)		$	(16.68)		(286)	%	(281)	%
Earnings per share information (in thousands, except per share data): (3)
Basic weighted-average common shares outstanding				114,759			114,528			113,009			231			1,750			—	%	2	%
Diluted weighted-average common shares outstanding				114,759			114,528			113,009			231			1,750			—	%	2	%
Basic net loss per common share				$	(2.19)		$	(1.44)		$	(3.64)		$	(0.75)		$	1.45		(52)	%	40	%
Diluted net loss per common share				$	(2.19)		$	(1.44)		$	(3.64)		$	(0.75)		$	1.45		(52)	%	40	%

______________________________________

(1) Amounts and percentage changes may not calculate due to rounding.

(2) Derivative settlements for the three months ended March 31, 2021, and 2020 are included within the net derivative (gain) loss line item in the accompanying statements of operations.

(3) Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.

Average net daily equivalent production for the three months ended March 31, 2021, decreased nine percent compared with the three months ended December 31, 2020, and decreased 18 percent compared with the three months ended March 31, 2020. These decreases were primarily driven by lower capital expenditures in the fourth quarter of 2020 and the first quarter of 2021, compared with the fourth quarter of 2019 and the first quarter of 2020, and the Texas Weather Event.

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 for the three months ended March 31, 2021, increased $13.69 per BOE and $13.47 per BOE compared with the three months ended December 31, 2020, and March 31, 2020, respectively. These increases were primarily driven by strengthening benchmark commodity prices during the first quarter of 2021, which included increased gas prices resulting from the supply and demand imbalance caused by the Texas Weather Event. For the three months ended March 31, 2021, the positive impact on oil, gas, and NGL production revenues associated with the increase in our realized price before the effect of derivative settlements on a per BOE basis was partially offset by a loss on the settlement of our derivative contracts of $10.74 per BOE for the same period, compared with gains on the settlement of our derivative contracts of $5.77 per BOE and $5.94 per BOE for the three months ended December 31, 2020, and March 31, 2020, respectively.

Lease operating expense (“LOE”) on a per BOE basis for the three months ended March 31, 2021, increased 13 percent compared with the three months ended December 31, 2020, and remained relatively flat compared with the three months ended March 31, 2020. The sequential quarterly increase was driven by an 11 percent decrease in total net equivalent production volumes. For the full year 2021, we expect LOE on a per BOE basis to increase, compared with 2020, due to higher oil production and increased workover expense. 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 impact total LOE.

Transportation costs on a per BOE basis for the three months ended March 31, 2021, remained relatively flat compared with the three months ended December 31, 2020, and decreased five percent compared with the three months ended March 31, 2020. The year-over-year decrease was driven by a 33 percent decrease in production volumes from our South Texas assets, which incur the majority of our transportation costs. We expect total transportation costs to fluctuate relative to changes in production from our South Texas assets. On a per BOE basis, we expect transportation costs to decrease for the full year 2021, compared with 2020, as production from our Midland Basin assets, which is sold at or near the wellhead and incurs minimal transportation costs, comprises a larger portion of our total production. Further, we anticipate natural declines in production from our Eagle Ford shale wells in South Texas, which incur higher transportation costs on a per BOE basis, and we intend to focus on new wells with higher liquids content in the Austin Chalk, which have lower transportation costs on a per BOE basis. In addition, we expect to benefit from certain transportation contract cost reductions that are expected to further reduce our transportation expense per BOE during 2021.

Production taxes on a per BOE basis for the three months ended March 31, 2021, increased 69 percent and 62 percent compared with the three months ended December 31, 2020, and March 31, 2020, respectively. These increases were primarily driven by the increase in realized prices before the effect of derivative settlements during the three months ended March 31, 2021. Our overall production tax rate for the three months ended March 31, 2021, was 4.6 percent compared with 4.0 percent and 4.2 percent for the three months ended December 31, 2020, and March 31, 2020, respectively. We expect our total production tax expense to increase in 2021, compared with 2020, as we expect oil, gas, and NGL production revenue to increase due to increased pricing. We generally expect production tax expense to correlate 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 that we recognize.

Ad valorem tax expense on a per BOE basis for the three months ended March 31, 2021, increased 37 percent and decreased 13 percent compared with the three months ended December 31, 2020, and March 31, 2020, respectively. The sequential quarterly increase was a result of decreased net equivalent production volumes. The year-over-year decrease was primarily a result of changes to the expected value assessments of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties change.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis for the three months ended March 31, 2021, remained relatively flat compared with the three months ended December 31, 2020, and decreased 12 percent compared with the three months ended March 31, 2020. The year-over-year decrease was primarily driven by the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020. 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. For the full year 2021, we expect DD&A per BOE and DD&A expense on an absolute basis to decrease compared with 2020, primarily as a result of anticipated higher production volumes.

General and administrative (“G&A”) expense on a per BOE basis for the three months ended March 31, 2021, increased 38 percent compared with the three months ended December 31, 2020, and increased 11 percent compared with the three months ended March 31, 2020. These increases were primarily the result of decreased production volumes during the three months ended March 31, 2021. For the full year 2021, we expect G&A expense to be relatively flat, in total and on a per BOE basis, compared with 2020.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2021, and December 31, 2020, and Between the Three Months Ended March 31, 2021, and 2020 below for additional discussion on operating expenses.

Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2021, and December 31, 2020, and Between the Three Months Ended March 31, 2021, and 2020

Net equivalent production, production revenue, and production expense

The following table presents the changes in our net equivalent production, production revenue, and production expense, by area, between the three months ended March 31, 2021, and December 31, 2020:


	Net Equivalent Production Decrease	Production Revenue Increase	Production Expense Increase (Decrease)

	(MBOE per day)	(in millions)	(in millions)
Midland Basin	(4.9)		$	96.3	$	6.2
South Texas	(5.9)		6.8		(1.2)
Total	(10.8)		$	103.0	$	5.0

__________________________________________

Note: Amounts may not calculate due to rounding.

Sequential quarterly change. Average net daily equivalent production volumes decreased nine percent driven by decreases of 14 percent and six percent in production volumes from our South Texas and Midland Basin assets, respectively. Realized prices before the effects of derivative settlements for oil, gas, and NGLs increased 39 percent, 69 percent, and 46 percent, respectively. As a result of increases in benchmark commodity prices during the first quarter of 2021, oil, gas, and NGL production revenue increased 32 percent. Total production expense increased five percent.

The following table presents the changes in our net equivalent production, production revenue, and production expense, by area, between the three months ended March 31, 2021, and 2020:


	Net Equivalent Production Decrease	Production Revenue Increase	Production Expense Decrease

	(MBOE per day)	(in millions)	(in millions)
Midland Basin	(7.3)		$	56.5	$	(8.9)
South Texas	(17.0)		12.4		(9.8)
Total	(24.2)		$	68.9	$	(18.6)

__________________________________________

Note: Amounts may not calculate due to rounding.

Year-over-year change. Average net daily equivalent production volumes decreased 18 percent, driven by decreases of 32 percent and nine percent in production volumes from our South Texas and Midland Basin assets, respectively. Realized prices before the effects of derivative settlements for oil, gas, and NGLs increased 23 percent, 170 percent, and 98 percent, respectively. As a result of increases in benchmark commodity prices, during the first quarter of 2021, oil, gas, and NGL production revenue increased 19 percent. Total production expense decreased 16 percent, primarily as a result of a decrease in average net daily equivalent production volumes causing decreases in LOE and transportation expenses.

Please refer to A Three Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.

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


	For the Three Months Ended
	March 31, 2021		December 31, 2020		March 31, 2020
	(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	167.0	$	188.9	$	233.5

DD&A expense for the three months ended March 31, 2021, decreased 12 percent compared with the three months ended December 31, 2020, and decreased 28 percent compared with the three months ended March 31, 2020. The sequential quarterly decrease was primarily driven by decreases in total net equivalent production volumes of 11 percent. The year-over-year decrease was driven by both a decrease in production volumes of 19 percent and the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020. Please refer to A Three Month Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.

Exploration


	For the Three Months Ended
	March 31, 2021		December 31, 2020		March 31, 2020
	(in millions)
Geological and geophysical expenses	$	0.3	$	2.6	$	1.2
Overhead and other expenses	9.0		8.7		10.1
Total	$	9.3	$	11.3	$	11.3

Exploration expense for the three months ended March 31, 2021, decreased 18 percent compared with each of the three months ended December 31, 2020, and March 31, 2020, primarily as a result of decreases in geological and geophysical expenses. Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and the potential for exploratory dry hole expense.

Impairment


	For the Three Months Ended
	March 31, 2021		December 31, 2020		March 31, 2020
	(in millions)
Impairment of proved oil and gas properties and related support equipment	$	—	$	—	$	956.7
Abandonment and impairment of unproved properties	8.8		8.8		33.1
Total	$	8.8	$	8.8	$	989.8

There were no proved oil and gas property impairments for the three months ended March 31, 2021, or December 31, 2020. During the three months ended March 31, 2020, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities 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. Unproved property abandonments and impairments recorded during each period presented above 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.

Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as of April 21, 2021, we do not expect any material property impairments in the second quarter of 2021 resulting from commodity price impacts.

Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for discussion of impairment expense.

General and administrative


	For the Three Months Ended
	March 31, 2021		December 31, 2020		March 31, 2020
	(in millions)
General and administrative	$	24.7	$	20.0	$	27.4

G&A expense increased 24 percent for the three months ended March 31, 2021, compared with the three months ended December 31, 2020, primarily as a result of increased expense related to employee stock compensation awards. G&A expense for the three months ended March 31, 2021, decreased 10 percent compared with the same period in 2020, primarily as a result of actions taken to reduce costs in response to the Pandemic. Please refer to the section A 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, 2021		December 31, 2020		March 31, 2020
	(in millions)
Net derivative (gain) loss	$	344.7	$	152.7	$	(545.3)

We recognized a derivative loss of $344.7 million for the three months ended March 31, 2021. The loss was primarily driven by a $236.8 million downward mark-to-market adjustment due to strengthening commodity prices during the first three months of the year. Additionally, we recognized losses on the settlement of derivative contracts of $107.9 million during the three months ended March 31, 2021.

We recognized a derivative loss of $152.7 million for the three months ended December 31, 2020. The loss was primarily driven by a $217.7 million downward mark-to-market adjustment partially offset by gains on the settlement of derivative contracts of $65.0 million during the three months ended December 31, 2020.

We recognized a derivative gain of $545.3 million 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. Additionally, we recognized gains on the settlement of derivative contracts of $73.4 million during the three months ended March 31, 2020.

Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Interest expense


	For the Three Months Ended
	March 31, 2021		December 31, 2020		March 31, 2020
	(in millions)
Interest expense	$	39.9	$	40.5	$	41.5

Interest expense for the three months ended March 31, 2021, remained relatively flat compared with the three months ended December 31, 2020, and decreased four percent, compared with the three months ended March 31, 2020. The year-over-year decrease was primarily due to an increase in interest expense capitalized to wells, partially offset by an increase in interest expense associated with borrowings under our revolving credit facility. We expect interest expense related to our Senior Notes to remain relatively flat for 2021 compared with 2020 as the increase related to the higher interest rate on the 2025 Senior Secured Notes will be mostly offset by the decreased interest associated with the reduction in principal of Senior Notes exchanged in 2020. Total interest expense is impacted by and can vary based on the timing and amount of borrowings under our revolving credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report and Overview of Liquidity and Capital Resources below for additional discussion.

Income tax (expense) benefit


	For the Three Months Ended
	March 31, 2021			December 31, 2020			March 31, 2020
	(in millions, except tax rate)
Income tax (expense) benefit	$	(0.1)		$	33.4		$	99.0
Effective tax rate	—		%	16.8		%	19.4		%

The decrease in the effective tax benefit rate for the three months ended March 31, 2021, compared with the three months ended December 31, 2020, was primarily due to the effects of forecasted income for the year ended December 31, 2021, compared to an actual loss in the fourth quarter of 2020, and the correlative effects on valuation allowance balances.

The decrease in the effective tax benefit rate for the three months ended March 31, 2021, compared with the same period in 2020, was primarily due to the effects of forecasted income for the year ended December 31, 2021, compared to forecasted loss at March 31, 2020. Also contributing to the decrease in the effective tax benefit rate are the relative effects of recording valuation allowance adjustments in each period.

For each of the comparable periods, the tax rates reflect the proportional effects of excess tax deficiencies from stock-based compensation awards, and limits on expensing of certain covered individual’s compensation.

During 2021, enactment of proposed legislation to increase the corporate tax rate and eliminate or reduce certain oil and gas industry deductions could have a material impact on the Company’s effective tax rate and current tax expense. Please refer to the Risk Factors section in Part I, Item 1A of our 2020 Form 10-K for additional discussion.

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 while continuing to meet our current financial obligations. 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, and we have successfully renegotiated certain contracts and have realized cost savings that directly support our objective of maximizing cash flows.

Sources of Cash

We expect our 2021 capital program to be funded by cash flows from operations. Although we expect cash flows from operations to be sufficient to fund our expected 2021 capital program, we may also use borrowings under our revolving credit facility or may 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 and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, tax law changes and volumes produced, all of which affect us and our industry.

Our credit ratings impact the availability of and cost for us to borrow additional funds. During the first quarter of 2021, and prior to filing, three major credit rating agencies upgraded our credit ratings, citing our improved debt leverage and our ability to generate meaningful free cash flows, among other reasons.

We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Please refer to Note 10 - Derivative Financial 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, and a borrowing base and aggregate lender commitments of $1.1 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. During March 2021, as a result of the regular, semi-annual redetermination, both the borrowing base and aggregate lender commitments were reaffirmed at the amounts noted above. The next scheduled borrowing base redetermination date is October 1, 2021. As of March 31, 2021, the remaining available borrowing capacity under our Credit Agreement provided $965.0 million in liquidity. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities, all as provided for in the Credit Agreement. 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 April 21, 2021, March 31, 2021, and December 31, 2020.

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. We were in compliance with all financial and non-financial covenants as of March 31, 2021, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Our daily weighted-average revolving credit facility debt balance for the three months ended March 31, 2021, was $134.2 million compared with $155.6 million and $104.1 million for the three months ended December 31, 2020, and March 31, 2020, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, including open market debt repurchases, repayment of scheduled debt maturities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Our Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. We currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business. Please refer to Note 1 - Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04 and ASU 2021-01, which provide 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 discounts related to the 2021 Senior Secured Convertible Notes and 2025 Senior Secured 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 each of the three months ended March 31, 2021, December 31, 2020, and March 31, 2020:


	For the Three Months Ended
	March 31, 2021		December 31, 2020		March 31, 2020
Weighted-average interest rate	7.7	%	7.5	%	6.5	%
Weighted-average borrowing rate	6.7	%	6.5	%	5.7	%

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. For the three months ended March 31, 2021, our weighted-average interest rate and our weighted-average borrowing rate remained flat compared with the three months ended December 31, 2020, and increased compared with the three months ended March 31, 2020. The year-over-year increase was primarily a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second quarter of 2020. The rates disclosed in the above table do not reflect amounts associated with the repurchase or redemption of Senior Notes, such as the acceleration of unamortized deferred financing costs, as these amounts are netted against the associated gain or loss on extinguishment of debt.

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, 2021, we spent approximately $147.6 million on capital expenditures. This amount differs from the costs incurred amount of $192.5 million for the three months ended March 31, 2021, 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 our cash flows from operating, investing, and financing activities, our ability to execute our development program, and the number and size of acquisitions. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. We entered 2021 with a total capital program budget between $650.0 million and $675.0 million. Given 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 further 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 redemptions may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or redemptions 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.

Please refer to Note 5 - Long-Term Debt and Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion. As part of our strategy for 2021, we will continue to focus on improving our debt metrics, which could include reducing the amount of our outstanding debt.

As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing each series of our outstanding Senior Notes, 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, 2021, 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 2021.

Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2021, and 2020

The following tables present changes in cash flows between the three months ended March 31, 2021, and 2020, 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
	2021		2020
	(in millions)
Net cash provided by operating activities	$	105.6	$	218.1	$	(112.5)

Net cash provided by operating activities decreased for the three months ended March 31, 2021, compared with the same period in 2020 primarily due to a $54.7 million decrease in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes and an increase of $86.8 million in cash paid on settled derivative trades, partially offset by decreased cash paid for LOE and ad valorem taxes of $19.4 million. 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
	2021		2020
	(in millions)
Net cash used in investing activities	$	(147.6)	$	(139.3)	$	(8.3)

Net cash used in investing activities increased $8.3 million for the three months ended March 31, 2021, compared with the same period in 2020, due to increased capital expenditures.

Financing activities


	For the Three Months Ended March 31,				Amount Change Between Periods
	2021		2020
	(in millions)
Net cash provided by (used in) financing activities	$	42.0	$	(78.8)	$	120.8

For the three months ended March 31, 2021, net borrowings under our revolving credit facility increased $42.0 million.

For the three months ended March 31, 2020, we repaid $50.5 million of our outstanding revolving credit facility balance. Also, 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. 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, 2021, we had a $135.0 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 Unsecured Notes or fixed-rate Senior Secured Notes but can impact their fair values. As of March 31, 2021, our outstanding principal amount of fixed-rate debt totaled $2.2 billion and our floating-rate debt outstanding totaled $135.0 million. Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior 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, and seasonal anomalies such as the Texas Weather Event, all of which are typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the Pandemic, however, future infection rate surges or outbreaks could have further negative impacts on prices. 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, 2021, 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 $30.6 million, $9.0 million, and $2.8 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the three months ended March 31, 2021, would have offset the declines in oil, gas, and NGL production revenue by approximately $36.1 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 March 31, 2021, 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 $154.2 million, $27.7 million, and $10.0 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, 2021, 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 2020 Form 10-K for discussion of our accounting policies and estimates.

New Accounting Pronouncements

Please refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for new accounting pronouncements.

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in the 2020 Form 10-K. 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 each series of our outstanding Senior 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, 2021		March 31, 2020
		(in thousands)
Net loss (GAAP)		$	(251,269)	$	(411,895)
Interest expense		39,871		41,512
Income tax expense (benefit)		106		(99,008)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		166,960		233,489
Exploration (1)		8,039		10,392
Impairment		8,750		989,763
Stock-based compensation expense		5,737		5,561
Net derivative (gain) loss		344,689		(545,340)
Derivative settlement gain (loss)		(107,885)		73,437

Gain on extinguishment of debt		—		(12,195)
Other, net		(10)		333
Adjusted EBITDAX (non-GAAP)		214,988		286,049
Interest expense		(39,871)		(41,512)
Income tax (expense) benefit		(106)		99,008
Exploration (1)		(8,039)		(10,392)
Amortization of debt discount and deferred financing costs		4,723		3,992
Deferred income taxes		(52)		(99,347)
Other, net		(14,582)		(1,149)
Net change in working capital		(51,437)		(18,517)
Net cash provided by operating activities (GAAP)		$	105,624	$	218,132

____________________________________________

(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.

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 2020 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 (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.

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

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the first quarter of 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely 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 trial is scheduled for November 8, 2021. Please refer to Legal Proceedings in Part I, Item 3 of our 2020 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 2020 Form 10-K.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2020 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no purchases made by us or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended March 31, 2021, 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.

In July 2006, our Board of Directors approved an increase in the number of shares of common stock 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 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, 2021, we did not repurchase any shares of our common stock pursuant to this Board of Director’s approval, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of 2021.

Our payment of cash dividends to our stockholders is subject to certain covenants under the terms of our Credit Agreement and Senior 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.

ITEM 6. EXHIBITS

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


Exhibit Number			Description
3.1			Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
3.2			Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)
31.1*			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2*			Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1**			Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
101.INS			Inline 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
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)

_____________________________________


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

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 30, 2021	By:	/s/ HERBERT S. VOGEL
		Herbert S. Vogel
		President and Chief Executive Officer
		(Principal Executive Officer)

April 30, 2021	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

April 30, 2021	By:	/s/ PATRICK A. LYTLE
		Patrick A. Lytle
		Vice President - Chief Accounting Officer and Controller and Assistant Secretary
		(Principal Accounting Officer)