sm-20210930

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 September 30, 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 October 21, 2021, the registrant had 121,473,790 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 September 30, 2021, and December 31, 2020	4

	Condensed Consolidated Statements of Operations Three and Nine Months Ended September 30, 2021, and 2020	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) Three and Nine Months Ended September 30, 2021, and 2020	6

	Condensed Consolidated Statements of Stockholders’ Equity Continuous Quarterly Presentation Ended September 30, 2021, and 2020	7

	Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2021, and 2020	9

	Notes to Condensed Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	42

	Part II	43

Item 1.	Legal Proceedings	43

Item 1A.	Risk Factors	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 6.	Exhibits	44

	Signatures	45

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,” “goal,” “intend,” “pending,” “plan,” “potential,” “projected,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:

•the impacts of the global COVID-19 pandemic (“Pandemic”) 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 farm-out of, or farm-in or joint development of, certain properties;

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

•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, debt or equity repurchases, capital markets activities, 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)


	September 30, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	29,800	$	10
Accounts receivable	272,248		162,455
Derivative assets	24,514		31,203
Prepaid expenses and other	9,708		10,001
Total current assets	336,270		203,669
Property and equipment (successful efforts method):
Proved oil and gas properties	9,271,463		8,608,522
Accumulated depletion, depreciation, and amortization	(5,439,387)		(4,886,973)
Unproved oil and gas properties	654,513		714,602
Wells in progress	142,259		233,498

Other property and equipment, net of accumulated depreciation of $65,462 and $63,662, respectively	36,635		32,217
Total property and equipment, net	4,665,483		4,701,866
Noncurrent assets:
Derivative assets	6,096		23,150
Other noncurrent assets	54,111		47,746
Total noncurrent assets	60,207		70,896
Total assets	$	5,061,960	$	4,976,431
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	542,474	$	371,670

Derivative liabilities	552,044		200,189
Other current liabilities	9,049		11,880
Total current liabilities	1,103,567		583,739
Noncurrent liabilities:
Revolving credit facility	—		93,000
Senior Notes, net	2,077,630		2,121,319


Asset retirement obligations	85,514		83,325


Derivative liabilities	90,655		22,331
Other noncurrent liabilities	67,695		56,557
Total noncurrent liabilities	2,321,494		2,376,532

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 121,473,790 and 114,742,304 shares, respectively	1,215		1,147
Additional paid-in capital	1,838,620		1,827,914
Retained earnings (deficit)	(190,367)		200,697
Accumulated other comprehensive loss	(12,569)		(13,598)
Total stockholders’ equity	1,636,899		2,016,160
Total liabilities and stockholders’ equity	$	5,061,960	$	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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	759,813	$	282,012	$	1,745,547	$	806,035

Other operating income (loss)	426		(997)		22,387		346
Total operating revenues and other income	760,239		281,015		1,767,934		806,381
Operating expenses:
Oil, gas, and NGL production expense	135,745		95,257		362,131		295,254
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	202,701		181,708		574,375		596,053
Exploration	8,709		8,547		26,746		29,683

Impairment	8,750		8,750		26,250		1,007,263
General and administrative	25,530		24,452		74,883		79,126
Net derivative (gain) loss	209,146		63,871		924,183		(314,269)
Other operating expense, net	43,401		1,562		44,654		10,174
Total operating expenses	633,982		384,147		2,033,222		1,703,284
Income (loss) from operations	126,257		(103,132)		(265,288)		(896,903)
Interest expense	(40,861)		(41,519)		(120,268)		(123,385)
Gain (loss) on extinguishment of debt	5		25,070		(2,139)		264,546
Other non-operating income (expense), net	153		(1,680)		(1,071)		(2,359)
Income (loss) before income taxes	85,554		(121,261)		(388,766)		(758,101)
Income tax benefit	39		22,969		95		158,662
Net income (loss)	$	85,593	$	(98,292)	$	(388,671)	$	(599,439)

Basic weighted-average common shares outstanding	121,457		114,371		118,224		113,462
Diluted weighted-average common shares outstanding	123,851		114,371		118,224		113,462
Basic net income (loss) per common share	$	0.70	$	(0.86)	$	(3.29)	$	(5.28)
Diluted net income (loss) per common share	$	0.69	$	(0.86)	$	(3.29)	$	(5.28)
Dividends per common share	$	0.01	$	0.01	$	0.02	$	0.02

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(in thousands)


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
Net income (loss)	$	85,593	$	(98,292)	$	(388,671)	$	(599,439)
Other comprehensive income, net of tax:
Pension liability adjustment	246		1,195		1,029		1,573
Total other comprehensive income, net of tax	246		1,195		1,029		1,573
Total comprehensive income (loss)	$	85,839	$	(97,097)	$	(387,642)	$	(597,866)

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
Net loss	—	—		—		(222,995)		—		(222,995)
Other comprehensive income	—	—		—		—		592		592
Cash dividends, $0.01 per share	—	—		—		(31)		—		(31)
Issuance of common stock under Employee Stock Purchase Plan	252,665	3		1,312		—		—		1,315

Stock-based compensation expense	57,795	1		3,955		—		—		3,956
Issuance of common stock through cashless exercise of Warrants	5,918,089	59		(59)		—		—		—

Balances, June 30, 2021	120,970,853	$	1,210	$	1,838,859	$	(274,745)	$	(12,815)	$	1,552,509
Net income	—	—		—		85,593		—		85,593
Other comprehensive income	—	—		—		—		246		246
Cash dividends declared, $0.01 per share	—	—		—		(1,215)		—		(1,215)

Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	502,937	5		(4,737)		—		—		(4,732)
Stock-based compensation expense	—	—		4,498		—		—		4,498


Balances, September 30, 2021	121,473,790	$	1,215	$	1,838,620	$	(190,367)	$	(12,569)	$	1,636,899

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued)

(in thousands, except share data and dividends per share)


				Additional Paid-in 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
Net loss	—	—		—		(89,252)		—		(89,252)
Other comprehensive income	—	—		—		—		188		188

Issuance of common stock under Employee Stock Purchase Plan	297,013	3		944		—		—		947

Stock-based compensation expense	267,576	3		5,709		—		—		5,712

Issuance of Warrants	—	—		21,520		—		—		21,520

Balances, June 30, 2020	113,553,271	$	1,136	$	1,825,327	$	465,310	$	(10,941)	$	2,280,832
Net loss	—	—		—		(98,292)		—		(98,292)
Other comprehensive income	—	—		—		—		1,195		1,195
Cash dividends declared, $0.01 per share	—	—		—		(1,146)		—		(1,146)

Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	1,019,529	10		(1,567)		—		—		(1,557)
Stock-based compensation expense	—	—		4,164		—		—		4,164

Other	—	—		(88)		—		—		(88)
Balances, September 30, 2020	114,572,800	$	1,146	$	1,827,836	$	365,872	$	(9,746)	$	2,185,108

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 Nine Months Ended September 30,
	2021		2020
Cash flows from operating activities:
Net loss	$	(388,671)	$	(599,439)
Adjustments to reconcile net loss to net cash provided by operating activities:

Depletion, depreciation, amortization, and asset retirement obligation liability accretion	574,375		596,053
Impairment	26,250		1,007,263
Stock-based compensation expense	14,191		15,437
Net derivative (gain) loss	924,183		(314,269)
Derivative settlement gain (loss)	(480,262)		286,270
Amortization of debt discount and deferred financing costs	13,350		13,084
(Gain) loss on extinguishment of debt	2,139		(264,546)
Deferred income taxes	(282)		(159,064)
Other, net	(7,301)		(6,294)
Net change in working capital	52,170		(40,411)





Net cash provided by operating activities	730,142		534,084

Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	8,835		92
Capital expenditures	(550,265)		(419,777)
Acquisition of proved and unproved oil and gas properties	(3,321)		(7,075)

Net cash used in investing activities	(544,751)		(426,760)

Cash flows from financing activities:
Proceeds from revolving credit facility	1,649,500		1,165,500
Repayment of revolving credit facility	(1,742,500)		(1,110,000)
Net proceeds from Senior Notes	392,771		—
Cash paid to repurchase Senior Notes	(450,776)		(147,770)
Debt issuance costs related to 10.0% Senior Secured Notes due 2025	—		(12,886)
Net proceeds from sale of common stock	1,315		947
Dividends paid	(1,178)		(1,130)
Other, net	(4,733)		(1,985)
Net cash used in financing activities	(155,601)		(107,324)

Net change in cash, cash equivalents, and restricted cash	29,790		—
Cash, cash equivalents, and restricted cash at beginning of period	10		10
Cash, cash equivalents, and restricted cash at end of period	$	29,800	$	10

Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest	$	(126,228)	$	(122,174)

Investing activities:
Increase (decrease) in capital expenditure accruals and other	$	8,885	$	(17,405)
Non-cash financing activities (1)

____________________________________________

(1) Please refer to Note 5 - Long-Term Debt for discussion of the debt transactions completed during the nine months ended September 30, 2021, and 2020.

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 September 30, 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”), and in January 2021, issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), 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 September 30, 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 September 30, 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 tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating areas for the three and nine months ended September 30, 2021, and 2020:


	Midland Basin						South Texas						Total
	Three Months Ended September 30,						Three Months Ended September 30,						Three Months Ended September 30,
	2021			2020			2021			2020			2021			2020

	(in thousands)
Oil production revenue	$	501,071		$	194,547		$	57,323		$	13,100		$	558,394		$	207,647
Gas production revenue	96,082			23,304			52,878			26,251			148,960			49,555
NGL production revenue	103			115			52,356			24,695			52,459			24,810
Total	$	597,256		$	217,966		$	162,557		$	64,046		$	759,813		$	282,012
Relative percentage	79		%	77		%	21		%	23		%	100		%	100		%

____________________________________________

Note: Amounts may not calculate due to rounding.


	Midland Basin						South Texas						Total
	Nine Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020			2021			2020

	(in thousands)
Oil production revenue	$	1,191,668		$	585,041		$	108,871		$	33,815		$	1,300,539		$	618,856
Gas production revenue	205,323			46,559			121,630			78,569			326,953			125,128
NGL production revenue	315			218			117,740			61,833			118,055			62,051
Total	$	1,397,306		$	631,818		$	348,241		$	174,217		$	1,745,547		$	806,035
Relative percentage	80		%	78		%	20		%	22		%	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 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 September 30, 2021, and December 31, 2020, were $227.5 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, in connection with the Exchange Offers described below in Note 5 - Long-Term Debt, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its then outstanding common stock, at an exercise price of $0.01 per share (“Warrants”).

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

The Warrant Agreement, dated as of June 17, 2020 (“Warrant Agreement”), provides that the Warrants are exercisable any time from and after the Triggering Date, as subsequently defined, until June 30, 2023. The Triggering Date, which occurred on January 15, 2021, 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 are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement, if exercised.

During the second quarter of 2021, the Company issued 5,918,089 shares of common stock as a result of the cashless exercise of 5,922,260 Warrants at a weighted-average share price of $15.45 per share, as determined under the terms of the Warrant Agreement. At the request of stockholders and pursuant to the Company’s obligations under the Warrant Agreement, a registration statement covering the resale of a majority of these shares was filed with the U.S. Securities and Exchange Commission on June 11, 2021. No Warrants were exercised during the third quarter of 2021. The unexercised Warrants will remain exercisable at the election of the holders until their expiration on June 30, 2023.

Note 4 - Income Taxes

The provision for income taxes for the three and nine months ended September 30, 2021, and 2020, consisted of the following:


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2021			2020			2021			2020

	(in thousands)
Current portion of income tax (expense) benefit:
Federal	$	—		$	—		$	—		$	—
State	(29)			173			(187)			(402)
Deferred portion of income tax benefit	68			22,796			282			159,064
Income tax benefit	$	39		$	22,969		$	95		$	158,662

Effective tax rate	—		%	18.9		%	—		%	20.9		%

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 and the resulting income tax benefit can also be affected by the proportional impacts of forecasted net income or loss and the correlative effect on the valuation allowance 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 September 30, 2021, and December 31, 2020:


	As of September 30, 2021		As of December 31, 2020

	(in thousands)
Revolving credit facility	$	—	$	93,000
Senior Secured Notes (1)	405,007		460,656
Senior Unsecured Notes (1)	1,672,623		1,660,663
Total	$	2,077,630	$	2,214,319

____________________________________________

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

Credit Agreement

The Company’s Credit Agreement, which is scheduled to mature on September 28, 2023, provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion. On June 8, 2021, the Company entered into a sixth amendment to the Credit Agreement to amend certain definitions and covenants relating to the Company's ability to issue permitted refinancing debt and to repurchase or redeem outstanding indebtedness to facilitate the Tender Offer and the 2022 Senior Notes Redemption, each as defined below. As of September 30, 2021, the borrowing base and aggregate lender commitments under the Credit Agreement were $1.1 billion. Subsequent to September 30, 2021, the fall semi-annual borrowing base redetermination was completed, which reaffirmed both the Company’s borrowing base and aggregate lender commitments at $1.1 billion. The next scheduled borrowing base redetermination date is April 1, 2022.

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 and ASU 2021-01, which provides guidance related to reference rate reform.

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of October 21, 2021, September 30, 2021, and December 31, 2020:


	As of October 21, 2021		As of September 30, 2021		As of December 31, 2020

	(in thousands)
Revolving credit facility (1)	$	—	$	—	$	93,000
Letters of credit (2)	2,500		2,500		42,000
Available borrowing capacity	1,097,500		1,097,500		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 $3.1 million and $4.3 million as of September 30, 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 September 30, 2021, and December 31, 2020, consisted of the following (collectively referred to as “Senior Secured Notes”):


	As of September 30, 2021
	Principal Amount		Unamortized Debt Discount		Unamortized Deferred Financing Costs		Net

	(in thousands)

10.0% Senior Secured Notes due 2025	$	446,675	$	32,232	$	9,436	$	405,007


	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 Senior Secured Notes listed above 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.

The 1.50% Senior Secured Convertible Notes due 2021 (“2021 Senior Secured Convertible Notes”) matured on July 1, 2021, and on that day, the Company used borrowings under its revolving credit facility to retire at par the outstanding principal amount of $65.5 million. Interest expense recognized on the 2021 Senior Secured Convertible Notes related to the stated interest rate and amortization of the debt discount. No interest expense was recognized for the three months ended September 30, 2021, $1.1 million was recognized for the three months ended September 30, 2020, and $2.3 million and $6.6 million was recognized for the nine months ended September 30, 2021, and 2020, respectively.

The Company may redeem some or all of its 10.0% Senior Secured Notes due 2025 (“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.

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 September 30, 2021, and December 31, 2020, consisted of the following (collectively referred to as “Senior Unsecured Notes,” and together with the Senior Secured Notes, “Senior Notes”):


	As of September 30, 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	$	855	$	211,548
5.0% Senior Notes due 2024	104,769		451		104,318		277,034		1,576		275,458
5.625% Senior Notes due 2025	349,118		2,318		346,800		349,118		2,792		346,326
6.75% Senior Notes due 2026	419,235		3,445		415,790		419,235		3,970		415,265
6.625% Senior Notes due 2027	416,791		4,143		412,648		416,791		4,725		412,066
6.5% Senior Notes due 2028	400,000		6,933		393,067		—		—		—
Total	$	1,689,913	$	17,290	$	1,672,623	$	1,674,581	$	13,918	$	1,660,663

The Senior Unsecured Notes listed above 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.

Senior Notes Activity

Second Quarter 2021 Senior Notes Transactions. On June 23, 2021, the Company issued $400.0 million in aggregate principal amount of its 6.5% Senior Notes at par with a maturity date of July 15, 2028 (“2028 Senior Notes”). The Company received net proceeds of $392.8 million after deducting fees of $7.2 million, which are being amortized as deferred financing costs over the life of the 2028 Senior Notes. The net proceeds were used to repurchase $193.1 million and $172.3 million of outstanding principal amount of the Company’s 6.125% Senior Notes due 2022 (“2022 Senior Notes”) and 5.0% Senior Notes due 2024 (“2024 Senior Notes”), respectively, through a cash tender offer (“Tender Offer”), and to redeem the remaining $19.3 million of 2022 Senior Notes not repurchased as part of the Tender Offer (“2022 Senior Notes Redemption”). The Company paid total consideration, excluding accrued interest, of $385.3 million, and recorded a net loss on extinguishment of debt of $2.1 million for the three months ended June 30, 2021, which included $1.5 million of accelerated unamortized deferred financing costs and $0.6 million of net premiums. The Company canceled all repurchased and redeemed 2022 Senior Notes and 2024 Senior Notes upon settlement.

Second Quarter 2020 Senior Notes Transactions. During the second quarter of 2020, the Company initiated an offer to exchange certain of its then outstanding Senior Unsecured Notes, other than its 1.50% Senior Unsecured Convertible Notes due 2021 (“2021 Senior Unsecured Convertible Notes,” and together with the Senior Unsecured Notes, “Old Notes”), and entered into a private exchange of certain of its then outstanding 2021 Senior Unsecured Convertible Notes and portions of its then outstanding Senior Unsecured Notes (“Private Exchange”), in each case, for newly issued 2025 Senior Secured Notes, referred to together as “Exchange Offers.”

On June 17, 2020, the Company exchanged $611.9 million in aggregate principal amount of Senior Unsecured Notes and $107.0 million in aggregate principal amount of 2021 Senior Unsecured Convertible Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes. Further, in connection with the Private Exchange, the Company tendered $53.5 million in cash to certain holders of the 2021 Senior Unsecured Convertible Notes and issued the Warrants. Please refer to Note 3 - Equity for more information regarding the Warrants. Upon the closing of the Exchange Offers, the Company recorded a net gain on extinguishment of debt of $227.3 million which included the recognition of $6.1 million and $5.6 million of previously unamortized debt discount and deferred financing costs, respectively. The Company canceled all Senior Unsecured Notes and 2021 Senior Unsecured Convertible Notes that were retired upon closing of the Exchange Offers. Pursuant to the indenture governing its 2021 Senior Unsecured Convertible Notes, the Company’s remaining outstanding 2021 Senior Unsecured Convertible Notes became secured. Please refer to Note 5 - Long-Term Debt in the 2020 Form 10-K for additional information regarding the debt transactions that occurred during the second quarter of 2020.

First Quarter and Third Quarter 2020 Senior Notes Transactions. During the nine months ended September 30, 2020, the Company repurchased $103.2 million in aggregate principal amount of its 2022 Senior Notes and $29.0 million in aggregate principal amount of its 2024 Senior Notes in open market transactions at a discount, for a total settlement amount, excluding accrued interest, of $94.2 million. In connection with the repurchases, the Company recorded a net gain on extinguishment of debt of $25.1 million and $37.3 million for the three and nine months ended September 30, 2020, respectively. The net gain on extinguishment of debt includes discounts realized upon repurchase of $25.5 million and $37.9 million for the three and nine months ended September 30, 2020, respectively, partially offset by accelerated unamortized deferred financing costs of $0.5 million and $0.7 million for the three and nine months ended September 30, 2020, respectively. The Company canceled all repurchased 2022 Senior Notes and 2024 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 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, create liens that secure debt, enter into transactions with affiliates, merge or consolidate with another company, and with respect to the Company’s restricted subsidiaries, permit the consensual restriction on the ability of such restricted subsidiaries to pay dividends or indebtedness owing to the Company or to any other restricted subsidiaries. The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of September 30, 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 for the three months ended September 30, 2021, and 2020, totaled $3.5 million and $4.8 million, respectively, and totaled $12.5 million and $11.6 million for the nine months ended September 30, 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 nine months ended September 30, 2021, the Company amended certain of its drilling rig contracts resulting in the extension of contract terms. As of September 30, 2021, the Company’s drilling rig commitments totaled $8.6 million under contract terms extending through the second quarter of 2022. If all of these contracts were terminated as of September 30, 2021, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $5.1 million in early termination fees. No material expenses related to early termination or standby fees were incurred by the Company during the nine months ended September 30, 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 first quarter of 2021, the Company amended an agreement that includes 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 September 30, 2021, the liquidated damages could range from zero to a maximum of $25.9 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.

Other Contracts. During the second quarter of 2021, the Company entered into an operating lease with a total estimated obligation of $25.8 million and an initial term extending through the second quarter of 2033. As of the filing of this report, the Company expects to meet this commitment.

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

As of September 30, 2021, 4.2 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”). The Company may also grant other types of long-term incentive-based awards, such as cash awards and performance-based cash awards, to eligible employees under its compensation plan.

Performance Share Units

The Company has granted 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.

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 $0.8 million and $1.6 million for the three months ended September 30, 2021, and 2020, respectively, and $5.3 million and $7.0 million for the nine months ended September 30, 2021, and 2020, respectively. As of September 30, 2021, there was $2.2 million of total unrecognized compensation expense related to non-vested PSUs, which is being amortized through 2022.

A summary of activity during the nine months ended September 30, 2021, is presented in the following table:


	PSUs (1)	Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	830,464	$	17.52
Granted	—	$	—
Vested	(352,395)	$	23.81
Forfeited	(12,222)	$	15.76
Non-vested at end of quarter	465,847	$	12.80

____________________________________________

(1) The number of shares of common stock assumes a multiplier of one. The actual final number of shares of common stock to be issued will range from zero to two times the number of PSUs awarded depending on the three-year performance multiplier.

During the nine months ended September 30, 2021, the Company settled PSUs that were granted in 2018, which earned a 1.0 times multiplier. The Company and all eligible recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. After withholding 112,919 shares to satisfy income and payroll tax withholding obligations, 234,823 shares of the Company’s common stock were issued in accordance with the terms of the applicable award agreement.

Employee Restricted Stock Units

The Company grants restricted stock units (“RSUs”) to eligible persons as part of its Equity Plan. Each of the RSUs granted represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest 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 individual RSU is equal to the closing price of the Company’s common stock on the date of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for employee RSUs was $2.9 million and $1.8 million for the three months ended September 30, 2021, and 2020, respectively, and $7.2 million and $7.1 million for the nine months ended September 30, 2021, and 2020, respectively. As of September 30, 2021, there was $23.7 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through 2024.

A summary of activity during the nine months ended September 30, 2021, is presented in the following table:


	RSUs	Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	2,097,860	$	8.83
Granted	661,402	$	25.47
Vested	(394,930)	$	16.69
Forfeited	(67,619)	$	10.25
Non-vested at end of quarter	2,296,713	$	12.23

During the nine months ended September 30, 2021, the Company settled RSUs upon the vesting of awards granted in previous years. The Company and all eligible recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. After withholding 106,543 shares to satisfy income and payroll tax withholding obligations, 268,114 shares of the Company’s common stock were issued in accordance with the terms of the applicable award agreements.

Director Shares

During the second quarters of 2021, and 2020, the Company issued 57,795 and 267,576 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. Shares issued during the second quarter of 2021 will fully vest on December 31, 2021. Shares issued during the second quarter of 2020 fully vested on December 31, 2020.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, subject to a maximum of 2,500 shares per offering period and a maximum of $25,000 in value related to purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the trading price of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the Internal Revenue Code. There were 252,665 and 297,013 shares issued under the ESPP during the nine months ended September 30, 2021, and 2020, respectively. Total proceeds to the Company for the issuance of these shares was $1.3 million and $0.9 million for the nine months ended September 30, 2021, and 2020, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Please refer to Note 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 September 30, 2021:


	Level 1		Level 2		Level 3

	(in thousands)
Assets:
Derivatives (1)	$	—	$	30,610	$	—

Liabilities:
Derivatives (1)	$	—	$	642,699	$	—

__________________________________________

(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 in this report, and to Note 10 - Derivative Financial Instruments and 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 material assets included in total property and equipment, net, measured at fair value as of September 30, 2021, or December 31, 2020.

The following table presents impairment of proved properties expense and abandonment and impairment of unproved properties expense recorded for the periods presented:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020

	(in thousands)
Impairment of proved oil and gas properties and related support equipment	$	—	$	—	$	—	$	956,650
Abandonment and impairment of unproved properties (1)	8,750		8,750		26,250		50,613
Impairment	$	8,750	$	8,750	$	26,250	$	1,007,263

____________________________________________

(1) These impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of September 30, 2021, and December 31, 2020, are recorded at carrying value.

For the nine months ended September 30, 2020, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities 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. 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 Notes obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of September 30, 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 September 30, 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	$	61,449
10.0% Senior Secured Notes due 2025	$	446,675	$	498,212	$	446,675	$	482,887
6.125% Senior Notes due 2022	$	—	$	—	$	212,403	$	205,379
5.0% Senior Notes due 2024	$	104,769	$	104,392	$	277,034	$	240,072
5.625% Senior Notes due 2025	$	349,118	$	351,935	$	349,118	$	289,401
6.75% Senior Notes due 2026	$	419,235	$	428,773	$	419,235	$	342,385
6.625% Senior Notes due 2027	$	416,791	$	426,952	$	416,791	$	331,220
6.5% Senior Notes due 2028	$	400,000	$	414,352	$	—	$	—

As of December 31, 2020, the carrying value of the Company’s revolving credit facility approximated 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. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and Warrants, all of which were measured using the treasury stock method. The Warrants became exercisable at the election of the holders on January 15, 2021, and as a result, they were included as potentially dilutive securities on an adjusted weighted-average basis for the portion of the three and nine months ended September 30, 2021, for which they were outstanding. 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.

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 September 30,		For the Nine Months Ended September 30,
	2021	2020	2021	2020

	(in thousands)
Anti-dilutive	—	158	5,200	450

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


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020

	(in thousands, except per share data)
Net income (loss)	$	85,593	$	(98,292)	$	(388,671)	$	(599,439)

Basic weighted-average common shares outstanding	121,457		114,371		118,224		113,462
Dilutive effect of non-vested RSUs and contingent PSUs	2,375		—		—		—
Dilutive effect of warrants	19		—		—		—
Diluted weighted-average common shares outstanding	123,851		114,371		118,224		113,462

Basic net income (loss) per common share	$	0.70	$	(0.86)	$	(3.29)	$	(5.28)
Diluted net income (loss) per common share	$	0.69	$	(0.86)	$	(3.29)	$	(5.28)

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 September 30, 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, natural gas, and NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

The Company has entered into fixed price oil and natural gas basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production 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 oil production with sales contracts that settle at WTI Midland prices,

•NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices,

•NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“MEH”) for a portion of its South Texas oil production with sales contracts that settle at Argus WTI Houston MEH prices, and

•NYMEX Henry Hub (“HH”) and Inside FERC Tennessee Texas, Zone 0 (“IF Tenn TX Z0”) for a portion of its South Texas gas production with sales contracts that settle at IF Tenn TX Z0 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 September 30, 2021, the Company had commodity derivative contracts outstanding through the fourth quarter of 2023 as summarized in the table below.


	Contract Period
	Fourth Quarter 2021		2022		2023
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes	5,052		7,823		1,190
Weighted-Average Contract Price	$	41.70	$	44.69	$	45.20
Collars
NYMEX WTI Volumes	—		2,342		—
Weighted-Average Floor Price	$	—	$	54.00	$	—
Weighted-Average Ceiling Price	$	—	$	61.39	$	—
Basis Swaps
WTI Midland-NYMEX WTI Volumes	3,824		9,500		—
Weighted-Average Contract Price (1)	$	0.71	$	1.15	$	—
NYMEX WTI-ICE Brent Volumes	920		3,650		—
Weighted-Average Contract Price (2)	$	(7.86)	$	(7.78)	$	—
WTI Houston MEH-NYMEX WTI Volumes	466		1,329		—
Weighted-Average Contract Price (3)	$	0.60	$	1.25	$	—
Roll Differential Swaps
NYMEX WTI Volumes	3,831		11,278		1,832
Weighted-Average Contract Price	$	(0.16)	$	0.11	$	0.39

Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps (4)
IF HSC Volumes	12,412		28,932		—
Weighted-Average Contract Price	$	2.41	$	2.52	$	—
WAHA Volumes	7,627		14,087		—
Weighted-Average Contract Price	$	1.82	$	2.32	$	—
IF Tenn TX Z0	—		513		—
Weighted-Average Contract Price	$	—	$	3.22	$	—
Collars
NYMEX HH Volumes	—		2,129		—
Weighted-Average Floor Price	$	—	$	3.40	$	—
Weighted-Average Ceiling Price	$	—	$	5.91	$	—
Basis Swaps
IF Tenn TX Z0-NYMEX HH Volumes	—		1,254		—
Weighted-Average Contract Price (5)	$	—	$	0.04	$	—

NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
OPIS Propane Mont Belvieu Non-TET Volumes	917		580		—
Weighted-Average Contract Price	$	24.58	$	29.71	$	—
OPIS Normal Butane Mont Belvieu Non-TET Volumes	36		—		—
Weighted-Average Contract Price	$	30.87	$	—	$	—
Collars
OPIS Propane Mont Belvieu Non-TET Volumes	—		770		—
Weighted-Average Floor Price	$	—	$	25.78	$	—
Weighted-Average Ceiling Price	$	—	$	31.60	$	—

____________________________________________

(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).

(4) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas, and Platt’s Gas Daily West Texas (“IF WAHA” and “GD WAHA”, respectively, and together “WAHA”), and IF Tenn TX Z0. As of September 30, 2021, WAHA volumes were comprised of 81 percent IF WAHA and 19 percent GD WAHA.

(5) Represents the price differential between IF Tenn TX Z0 (Corpus Christi, Texas) and NYMEX HH (Erath, Louisiana).

Commodity Derivative Contracts Entered Into Subsequent to September 30, 2021

Subsequent to September 30, 2021, the Company entered into the following commodity derivative contracts:

•NYMEX WTI oil collar contracts for the third quarter of 2022 for a total of 0.3 MMBbl of oil production at a floor price of $70.00 per Bbl and a weighted-average ceiling price of $73.52 per Bbl, and for the first quarter of 2023 for a total of 0.3 MMBbl of oil production at a floor price of $60.00 per Bbl and a ceiling price of $75.20 per Bbl; and

•an IF HSC gas collar contract for the first quarter of 2023 for a total of 900 BBtu of gas production at a floor price of $3.38 per MMBtu and a ceiling price of $7.75 per MMBtu.

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, 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 $612.1 million and $168.2 million as of September 30, 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 September 30, 2021		As of December 31, 2020

	(in thousands)
Derivative assets:
Current assets	$	24,514	$	31,203
Noncurrent assets	6,096		23,150
Total derivative assets	$	30,610	$	54,353
Derivative liabilities:
Current liabilities	$	552,044	$	200,189
Noncurrent liabilities	90,655		22,331
Total derivative liabilities	$	642,699	$	222,520

Offsetting of Derivative Assets and Liabilities

As of September 30, 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
	September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020

	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	30,610	$	54,353	$	(642,699)	$	(222,520)
Amounts not offset in the accompanying balance sheets	(30,610)		(53,598)		30,610		53,598
Net amounts	$	—	$	755	$	(612,089)	$	(168,922)

The following table summarizes the commodity components of the derivative settlement (gain) loss, and the net derivative (gain) loss line items presented within the accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) and within the accompanying statements of operations, respectively:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020

	(in thousands)
Derivative settlement (gain) loss:
Oil contracts	$	154,113	$	(68,907)	$	344,740	$	(261,095)
Gas contracts	35,757		(896)		88,437		(16,575)
NGL contracts	23,685		(502)		47,085		(8,600)
Total net derivative settlement (gain) loss	$	213,555	$	(70,305)	$	480,262	$	(286,270)

Net derivative (gain) loss:
Oil contracts	$	68,194	$	30,641	$	611,224	$	(360,649)
Gas contracts	109,802		31,548		220,088		46,537
NGL contracts	31,150		1,682		92,871		(157)
Total net derivative (gain) loss	$	209,146	$	63,871	$	924,183	$	(314,269)

Credit Related Contingent Features

As of September 30, 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. Additionally, the following discussion includes sequential quarterly comparison to financial information presented in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, filed with the SEC on July 30, 2021. Throughout the following discussion, we explain changes between the three months ended September 30, 2021, compared with the three months ended June 30, 2021 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the nine months ended September 30, 2021, compared with the same period in 2020 (“YTD 2021-over-YTD 2020”).

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 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 asset 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 impact 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, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on 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 third quarter of 2021, drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continued to focus primarily on delineating and developing 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”). For the nine months ended September 30, 2021, our operations in South Texas were focused on production from both the Eagle Ford shale formation and Austin Chalk formation, and further 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.

Third Quarter 2021 Overview and Outlook for the Remainder of 2021

During the third quarter of 2021, we remained committed to our goal of reducing the principal balance of our outstanding debt through cash flow generation. For the three months ended September 30, 2021, net cash provided by operating activities exceeded net cash used in investing activities by $153.3 million, and we reduced the principal balance of our outstanding debt by $118.0 million. We executed on this goal through strong operational performance and a diligent focus on cost management. Additionally, we benefited from increased commodity pricing which has improved from historic lows experienced during the height of the Pandemic due to increased demand.

The Pandemic remains a global health crisis and continues to evolve, with the Delta variant becoming the predominant strain of the virus worldwide. Despite the emergence of the Delta variant, the United States has experienced substantial improvements in financial markets and public health as a result of deployment of vaccines to prevent the spread of the COVID-19 virus. The markets for the commodities produced by our industry strengthened in recent months, but remain subject to heightened levels of uncertainty related to the Pandemic and other geopolitical issues. As a result, we are unable to reasonably estimate the extent that volatile market conditions could impact our business, results of operations, financial condition, or the timing of further recovery. Although demand for the commodities produced by our industry has increased, and associated prices have improved from historic lows in 2020, with sustained gas prices reaching their highest average price since 2014, further negative financial markets and industry-specific impacts

could result from future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, 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 impacts of the Pandemic, geopolitical issues, 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, the vast majority of our office-based employees have continued working remotely in order to limit physical interactions and to mitigate the spread of COVID-19. 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 have continued to be effective and we have continued to address new risks directly related to the Pandemic as we identify them.

Our 2021 total capital program budget is 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 that our high quality asset portfolio is capable of generating strong returns in the current macroeconomic environment, enabling us to grow cash flows, improve leverage metrics, and maintain strong financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2021 capital program.

Financial and Operational Results. Average net daily equivalent production for the three months ended September 30, 2021, increased 14 percent sequentially to 155.8 MBOE primarily driven by a 19 percent increase in oil volumes. These increases were the result of our focus on operational execution, strong well performance, and acceleration of capital activity in the second and third quarters of 2021.

Strengthening benchmark commodity prices in the third quarter of 2021 resulted in increased realized prices for oil, gas, and NGLs of six percent, 53 percent, and 30 percent, respectively, for the three months ended September 30, 2021, compared with the three months ended June 30, 2021. Total realized price per BOE increased 17 percent for the three months ended September 30, 2021, compared with the three months ended June 30, 2021. The increases in benchmark commodity prices, combined with the increase in production volumes, resulted in oil, gas, and NGL production revenue of $759.8 million for the three months ended September 30, 2021, compared with $562.6 million for the three months ended June 30, 2021, which was an increase of 35 percent. Production costs per BOE of $9.47 for the three months ended September 30, 2021, decreased six percent compared with the three months ended June 30, 2021, primarily as a result of decreases in transportation costs per BOE and lease operating expense (“LOE”) per BOE, partially offset by increases in production taxes per BOE.

We recorded net derivative losses of $209.1 million and $370.3 million for the three months ended September 30, 2021, and June 30, 2021, respectively. Included within these amounts are derivative settlement losses of $213.6 million and $158.8 million for the three months ended September 30, 2021, and June 30, 2021, respectively, resulting from increased benchmark commodity prices.

Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2021, and June 30, 2021, and Between the Nine Months Ended September 30, 2021, and 2020 below for additional discussion.

Financial and operational activities during the three months ended September 30, 2021, resulted in the following:

•Net cash provided by operating activities of $328.1 million for the three months ended September 30, 2021, compared with $296.4 million for the three months ended June 30, 2021.

•A cash balance of $29.8 million and no outstanding balance on the revolving credit facility as of September 30, 2021, compared with a revolving credit facility balance of $52.5 million as of June 30, 2021.

•Net income of $85.6 million, or $0.69 per diluted share, for the three months ended September 30, 2021, compared with a net loss of $223.0 million, or $1.88 per diluted share, for the three months ended June 30, 2021. Net income for the three months ended September 30, 2021, was primarily a result of increased production and pricing. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2021, and June 30, 2021, and Between the Nine Months Ended September 30, 2021, and 2020 below for additional discussion regarding the components of net income (loss) for the periods presented.

•Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2021, was $346.7 million, compared with $256.9 million for the three months ended June 30, 2021. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities.

Operational Activities. In our Midland Basin program, we operated an average of three drilling rigs and averaged one completion crew during the third quarter of 2021. We drilled 17 gross (14 net) wells and completed 30 gross (24 net) wells during the third quarter of 2021, and production volumes increased sequentially by 18 percent to 9.8 MMBOE. Costs incurred in our Midland Basin program during the three months ended September 30, 2021, totaled $101.5 million, or 59 percent of our total costs incurred for the period. We anticipate operating two drilling rigs and one completion crew at times during the remainder of 2021, focused primarily on developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions in the Midland Basin.

In our South Texas program, we operated an average of two drilling rigs and averaged one completion crew during the third quarter of 2021. We drilled 10 gross (10 net) wells and completed 11 gross (11 net) wells during the third quarter of 2021, and production volumes increased sequentially by 10 percent to 4.5 MMBOE. Costs incurred in our South Texas program during the three months ended September 30, 2021, totaled $59.3 million, or 34 percent of our total costs incurred for the period. We anticipate operating one drilling rig and one completion crew during the remainder of 2021, focused primarily on 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 and nine months ended September 30, 2021:


	Midland Basin		South Texas (2)		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	66	58	30	30	96	88
Wells drilled	14	11	11	11	25	22
Wells completed	(44)	(40)	(5)	(5)	(49)	(45)

Wells drilled but not completed at June 30, 2021	36	29	36	36	72	65
Wells drilled	17	14	10	10	27	24
Wells completed	(30)	(24)	(11)	(11)	(41)	(35)
Other (1)	—	(1)	—	—	—	(1)
Wells drilled but not completed at September 30, 2021	23	18	35	35	58	53

____________________________________________

(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, farm-outs, and other activities.

(2) The South Texas drilled but not completed well count as of each period end presented above 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 $172.5 million and $589.7 million for the three and nine months ended September 30, 2021, respectively, 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 sequential quarterly periods and the YTD 2021-over-YTD 2020 periods:


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020
Midland Basin Production:
Oil (MMBbl)	7.2		6.2		18.5		16.0
Gas (Bcf)	15.5		12.8		38.9		34.0
NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	9.8		8.3		25.0		21.6
Average net daily equivalent (MBOE per day)	106.7		91.6		91.6		79.0
Relative percentage	69	%	67	%	68	%	62	%

South Texas Production:
Oil (MMBbl)	0.8		0.5		1.7		1.3
Gas (Bcf)	13.6		13.6		38.2		44.6
NGLs (MMBbl)	1.4		1.3		3.8		4.8
Equivalent (MMBOE)	4.5		4.1		11.8		13.5
Average net daily equivalent (MBOE per day)	49.0		44.9		43.2		49.4
Relative percentage	31	%	33	%	32	%	38	%

Total Production:
Oil (MMBbl)	8.1		6.7		20.2		17.2
Gas (Bcf)	29.1		26.5		77.1		78.6
NGLs (MMBbl)	1.4		1.3		3.8		4.8
Equivalent (MMBOE)	14.3		12.4		36.8		35.2
Average net daily equivalent (MBOE per day)	155.8		136.5		134.8		128.3

____________________________________________

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 three months ended September 30, 2021, June 30, 2021, and September 30, 2020:


	For the Three Months Ended
	September 30, 2021		June 30, 2021		September 30, 2020
Oil (per Bbl):
Average NYMEX contract monthly price	$	70.56	$	66.07	$	40.93
Realized price, before the effect of derivative settlements	$	69.30	$	65.34	$	37.69
Effect of oil derivative settlements	$	(19.13)	$	(20.11)	$	12.51
Gas:
Average NYMEX monthly settle price (per MMBtu)	$	4.01	$	2.83	$	1.98
Realized price, before the effect of derivative settlements (per Mcf)	$	5.12	$	3.34	$	1.90
Effect of gas derivative settlements (per Mcf)	$	(1.23)	$	(0.46)	$	0.03
NGLs (per Bbl):
Average OPIS price (1)	$	40.39	$	31.52	$	19.13
Realized price, before the effect of derivative settlements	$	36.87	$	28.41	$	14.07
Effect of NGL derivative settlements	$	(16.65)	$	(9.22)	$	0.29

____________________________________________

(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 or likelihood of any future potential negative impacts of the Pandemic such as 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 Third 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 October 21, 2021, and September 30, 2021:


	As of October 21, 2021		As of September 30, 2021
NYMEX WTI oil (per Bbl)	$	77.90	$	72.54
NYMEX Henry Hub gas (per MMBtu)	$	4.53	$	4.88
OPIS NGLs (per Bbl)	$	42.31	$	41.74

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 September 30, 2021, and the preceding three quarters.


	For the Three Months Ended
	September 30,		June 30,		March 31,		December 31,
	2021		2021		2021		2020

	(in millions)
Production (MMBOE)	14.3		12.4		10.0		11.3
Oil, gas, and NGL production revenue	$	759.8	$	562.6	$	423.2	$	320.2
Oil, gas, and NGL production expense	$	135.7	$	125.5	$	100.9	$	96.0
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	202.7	$	204.7	$	167.0	$	188.9
Exploration	$	8.7	$	8.7	$	9.3	$	11.3
General and administrative	$	25.5	$	24.6	$	24.7	$	20.0
Net income (loss)	$	85.6	$	(223.0)	$	(251.3)	$	(165.2)

____________________________________________

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics


	For the Three Months Ended
	September 30,			June 30,			March 31,			December 31,
	2021			2021			2021			2020
Average net daily equivalent production (MBOE per day)	155.8			136.5			111.6			122.4
Lease operating expense (per BOE)	$	4.20		$	4.62		$	4.64		$	4.10
Transportation costs (per BOE)	$	2.41		$	3.01		$	2.94		$	2.89
Production taxes as a percent of oil, gas, and NGL production revenue	4.7		%	4.5		%	4.6		%	4.0		%
Ad valorem tax expense (per BOE)	$	0.38		$	0.45		$	0.52		$	0.38
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	14.14		$	16.48		$	16.62		$	16.77
General and administrative (per BOE)	$	1.78		$	1.98		$	2.46		$	1.78

____________________________________________

Note: Amounts may not calculate due to rounding.

Overview of Selected Production and Financial Information, Including Trends


	For the Three Months Ended				Amount Change Between Periods		Percent Change Between Periods		For the Nine Months Ended				Amount Change Between Periods			Percent Change Between Periods
	September 30,		June 30,						September 30,		September 30,
	2021		2021						2021		2020
Net production volumes: (1)
Oil (MMBbl)	8.1		6.7		1.4		21	%	20.2		17.2			2.9			17	%
Gas (Bcf)	29.1		26.5		2.6		10	%	77.1		78.6			(1.5)			(2)	%
NGLs (MMBbl)	1.4		1.3		0.1		7	%	3.8		4.8			(1.1)			(22)	%
Equivalent (MMBOE)	14.3		12.4		1.9		15	%	36.8		35.2			1.6			5	%
Average net daily production: (1)
Oil (MBbl per day)	87.6		73.4		14.2		19	%	73.9		62.9			11.0			17	%
Gas (MMcf per day)	316.3		290.9		25.4		9	%	282.5		286.7			(4.3)			(1)	%
NGLs (MBbl per day)	15.5		14.6		0.8		6	%	13.9		17.7			(3.8)			(22)	%
Equivalent (MBOE per day)	155.8		136.5		19.2		14	%	134.8		128.3			6.5			5	%
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue	$	558.4	$	436.4	$	122.0	28	%	$	1,300.5	$	618.9		$	681.7		110	%
Gas production revenue	149.0		88.3		60.6		69	%	327.0		125.1			201.8			161	%
NGL production revenue	52.5		37.9		14.6		39	%	118.1		62.1			56.0			90	%
Total oil, gas, and NGL production revenue	$	759.8	$	562.6	$	197.2	35	%	$	1,745.5	$	806.0		$	939.5		117	%
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense	$	60.1	$	57.4	$	2.7	5	%	$	164.2	$	138.1		$	26.1		19	%
Transportation costs	34.5		37.4		(2.9)		(8)	%	101.4		109.4			(8.0)			(7)	%
Production taxes	35.7		25.2		10.6		42	%	80.4		33.2			47.2			142	%
Ad valorem tax expense	5.4		5.6		(0.1)		(2)	%	16.2		14.6			1.6			11	%
Total oil, gas, and NGL production expense	$	135.7	$	125.5	$	10.3	8	%	$	362.1	$	295.3		$	66.9		23	%
Realized price, before the effect of derivative settlements (“realized price”):
Oil (per Bbl)	$	69.30	$	65.34	$	3.96	6	%	$	64.50	$	35.92		$	28.58		80	%
Gas (per Mcf)	$	5.12	$	3.34	$	1.78	53	%	$	4.24	$	1.59		$	2.65		167	%
NGLs (per Bbl)	$	36.87	$	28.41	$	8.46	30	%	$	31.19	$	12.81		$	18.38		143	%
Per BOE	$	53.02	$	45.28	$	7.74	17	%	$	47.43	$	22.92		$	24.51		107	%
Per BOE data: (1)
Production costs:
Lease operating expense	$	4.20	$	4.62	$	(0.42)	(9)	%	$	4.46	$	3.93		$	0.53		13	%
Transportation costs	2.41		3.01		(0.60)		(20)	%	2.75		3.11			(0.36)			(12)	%
Production taxes	2.49		2.03		0.46		23	%	2.18		0.94			1.24			132	%
Ad valorem tax expense	0.38		0.45		(0.07)		(16)	%	0.44		0.41			0.03			7	%
Total production costs (1)	$	9.47	$	10.10	$	(0.63)	(6)	%	$	9.84	$	8.40		$	1.44		17	%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	14.14	$	16.48	$	(2.34)	(14)	%	$	15.61	$	16.95		$	(1.34)		(8)	%
General and administrative	$	1.78	$	1.98	$	(0.20)	(10)	%	$	2.03	$	2.25		$	(0.22)		(10)	%
Derivative settlement gain (loss) (2)	$	(14.90)	$	(12.78)	$	(2.12)	(17)	%	$	(13.05)	$	8.14		$	(21.19)		(260)	%
Earnings per share information (in thousands, except per share data): (3)
Basic weighted-average common shares outstanding	121,457		118,357		3,100		3	%	118,224		113,462			4,762			4	%
Diluted weighted-average common shares outstanding	123,851		118,357		5,494		5	%	118,224		113,462			4,762			4	%
Basic net income (loss) per common share	$	0.70	$	(1.88)	$	2.58	137	%	$	(3.29)	$	(5.28)		$	1.99		38	%
Diluted net income (loss) per common share	$	0.69	$	(1.88)	$	2.57	137	%	$	(3.29)	$	(5.28)		$	1.99		38	%

______________________________________

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

(2) Derivative settlements for the three months ended September 30, 2021, and for the nine months ended September 30, 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 September 30, 2021, increased 14 percent sequentially as a result of increases of 16 percent and nine percent in average net daily equivalent production volumes from our Midland Basin assets and our South Texas assets, respectively. These increases were the result of our focus on operational execution, strong well performance, and acceleration of capital activity in the second and third quarters of 2021. Average net daily equivalent production for the nine months ended September 30, 2021, increased five percent compared with the same period in 2020, as a result of an increase of 16 percent in average net daily equivalent production volumes from our Midland Basin assets, resulting from an increased number of completions and strong well performance YTD 2021-over-YTD 2020.

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 on a per BOE basis increased $7.74 sequentially as a result of strengthening benchmark commodity prices. The positive impact on oil, gas, and NGL production revenues resulting from the sequential quarterly realized price increase was partially offset by an increase in the loss on the settlement of our derivative contracts of $2.12 per BOE. Our realized price on a per BOE basis increased $24.51 YTD 2021-over-YTD 2020, primarily as a result of higher benchmark commodity prices, which have improved from historic lows experienced during 2020 as a result of the impacts of the Pandemic and other macroeconomic events. Further contributing to the YTD 2021-over-YTD 2020 increase were increased gas prices during the first quarter of 2021 resulting from a supply and demand imbalance caused by a significant weather event in the state of Texas that lasted for several days in February 2021, which included abnormally low temperatures and freezing conditions, and resulted in widespread power outages. The positive impact on oil, gas, and NGL production revenues resulting from the YTD 2021-over-YTD 2020 realized price increase was substantially offset by a 260% change in the settlement of our derivative contracts which were a loss of $13.05 per BOE for the nine months ended September 30, 2021, compared to a gain of $8.14 per BOE for the same period in 2020.

LOE on a per BOE basis decreased nine percent sequentially, primarily as a result of production volume increases outpacing increases in total LOE due to operational efficiencies and cost savings associated with produced water recycling. LOE on a per BOE basis increased 13 percent YTD 2021-over-YTD 2020, driven by the increased percentage of oil in our total product mix, which has higher lifting costs per BOE, and increased workover expense. 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 decreased 20 percent sequentially and decreased 12 percent YTD 2021-over-YTD 2020. The sequential quarterly decrease was the result of an 18 percent increase in production volumes from our Midland Basin assets, which are sold at or near the wellhead and incur minimal transportation costs. Additionally, during the third quarter of 2021, we benefited from cost reductions on one of our transportation contracts. The YTD 2021-over-YTD 2020 decrease was the result of a 13 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 gas and NGL 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 we expect production from our Midland Basin assets to continue to comprise 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, one of our transportation contracts in South Texas has an embedded cost reduction that took effect during the third quarter of 2021 and, as a result, we expect a decrease in transportation costs on a per BOE basis for the full-year 2021 compared with 2020.

Production tax expense on a per BOE basis increased 23 percent sequentially, and increased 132 percent YTD 2021-over-YTD 2020, primarily driven by increases in realized prices and an increase in production from our Midland Basin assets. Our overall production tax rate was 4.7 percent and 4.5 percent for the three months ended September 30, 2021, and June 30, 2021, respectively, and 4.6 percent and 4.1 percent for the nine months ended September 30, 2021, and 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 decreased 16 percent sequentially and increased seven percent YTD 2021-over-YTD 2020. The sequential quarterly decrease was a result of increased net equivalent production volumes. The YTD 2021-over-YTD 2020 increase 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 changes.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis decreased 14 percent sequentially as a result of strong well performance, increased commodity pricing, and lower well costs in our Midland Basin assets. DD&A expense on a per BOE basis decreased eight percent YTD 2021-over-YTD 2020 due to the aforementioned reasons as well as 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 expense per BOE and DD&A expense on an absolute basis to decrease compared with 2020, primarily as a result of increased commodity pricing, strong well performance, lower well costs, and increased activity in our Austin Chalk program compared with 2020, as these assets have a lower DD&A rate than our Midland Basin assets.

General and administrative (“G&A”) expense on a per BOE basis decreased 10 percent both sequentially and YTD 2021-over-YTD 2020. These decreases were primarily the result of increased production volumes, and the YTD 2021-over-YTD 2020 decrease was partially driven by actions taken to reduce costs in response to the Pandemic. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year. For the full year 2021, we expect G&A expense to be relatively flat on an absolute basis, however could trend higher based on the impacts that increased commodity pricing and strong operational performance are having on the Company’s performance metrics through September 30, 2021.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2021, and June 30, 2021, and Between the Nine Months Ended September 30, 2021, and 2020 below for additional discussion on operating expenses.

Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2021, and June 30, 2021, and Between the Nine Months Ended September 30, 2021, and 2020

Net equivalent production, production revenue, and production expense

Sequential Quarterly Changes. The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the three months ended September 30, 2021, and June 30, 2021:


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

	(MBOE per day)	(in millions)	(in millions)
Midland Basin	15.1		$	141.2	$	11.0
South Texas	4.1		56.0		(0.7)
Total	19.2		$	197.2	$	10.3

__________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased 14 percent consisting of increases of 16 percent and nine percent in average net daily equivalent production volumes from our Midland Basin and South Texas assets, respectively. Realized prices for oil, gas, and NGLs increased six percent, 53 percent, and 30 percent, respectively. During the third quarter of 2021, as a result of increases in benchmark commodity prices for oil, gas, and NGLs and the increase in production volumes noted above, oil, gas, and NGL production revenue increased 35 percent. Total production expense increased eight percent as a result of increased production taxes resulting from higher oil, gas, and NGL revenues.

YTD 2021-over-YTD 2020. The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the nine months ended September 30, 2021, and 2020:


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

	(MBOE per day)	(in millions)	(in millions)
Midland Basin	12.6		$	765.5	$	62.5
South Texas	(6.2)		174.0		4.4
Total	6.5		$	939.5	$	66.9

__________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased five percent consisting of an increase of 16 percent in average net daily equivalent production volumes from our Midland Basin assets, partially offset by a decrease of 13 percent in average net daily equivalent production volumes from our South Texas assets. These changes were primarily the result of higher capital allocations to

the Midland Basin in prior years. Realized prices for oil, gas, and NGLs increased 80 percent, 167 percent, and 143 percent, respectively. As a result of increases in benchmark commodity prices, oil, gas, and NGL production revenue increased 117 percent. Total production expense increased 23 percent, primarily as a result of increased production taxes and LOE.

Please refer to 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				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020

	(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	202.7	$	204.7	$	574.4	$	596.1

DD&A expense remained flat sequentially and decreased four percent YTD 2021-over-YTD 2020. The YTD 2021-over-YTD 2020 decrease was driven by strong well performance, increased commodity pricing, lower well costs related to our Midland Basin assets, 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 Overview of Selected Production and Financial Information, Including Trends above for additional discussion of DD&A expense on a per BOE basis.

Exploration


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020

	(in millions)
Geological and geophysical expenses	$	(0.1)	$	0.8	$	1.0	$	1.7
Overhead and other expenses	8.8		7.9		25.7		28.0
Total	$	8.7	$	8.7	$	26.7	$	29.7

Exploration expense remained flat sequentially and decreased 10 percent YTD 2021-over-YTD 2020. The YTD 2021-over-YTD 2020 decrease was primarily a result of decreases in overhead and other expenses. Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and unsuccessful exploration activities, if any.

Impairment


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 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		26.3		50.6
Total	$	8.8	$	8.8	$	26.3	$	1,007.3

There were no proved oil and gas property impairments for the three and nine months ended September 30, 2021. During the nine months ended September 30, 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 October 21, 2021, we do not expect any material property impairments in the fourth 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 additional discussion of impairment expense.

General and administrative


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020

	(in millions)
General and administrative	$	25.5	$	24.6	$	74.9	$	79.1

G&A expense increased four percent sequentially as a result of changes in the fair value of certain awards made under our long-term equity compensation program, and decreased five percent YTD 2021-over-YTD 2020, primarily as a result of actions taken to reduce costs in response to the Pandemic. Please refer to the section 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				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020

	(in millions)


Net derivative (gain) loss	$	209.1	$	370.3	$	924.2	$	(314.3)

Net derivative (gain) loss is a result of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying our derivative contracts outstanding and the monthly cash settlements on settled derivative positions during the period. The net derivative losses for the three and nine months ended September 30, 2021, and the three months ended June 30, 2021, resulted from increases in benchmark commodity prices during 2021. The net derivative gain for the nine months ended September 30, 2020, was the result of decreases in benchmark commodity prices during 2020. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Other operating expense, net


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020

	(in millions)
Other operating expense, net	$	43.4	$	1.9	$	44.7	$	10.2

Other operating expense, net, increased both sequentially and YTD 2021-over-YTD 2020 as a result of legal settlements recorded during the third quarter of 2021, including the settlement of the SPM NAM LLC et al. case discussed in Legal Proceedings in Part II, Item 1 of this report. We do not expect material charges to other operating expenses for the remainder of 2021.

Interest expense


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020

	(in millions)
Interest expense	$	40.9	$	39.5	$	120.3	$	123.4

Interest expense increased three percent sequentially and decreased three percent YTD 2021-over-YTD 2020. We expect interest expense related to our Senior Notes to decrease slightly for 2021 compared with 2020 primarily as a result of the decreased

principal amount outstanding on our Senior Notes resulting from the Exchange Offers completed in the second quarter of 2020, and the retirement of our remaining 2021 Senior Secured Convertible Notes which matured on July 1, 2021. 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.

Gain (loss) on extinguishment of debt


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020

	(in millions)
Gain (loss) on extinguishment of debt	$	—	$	(2.1)	$	(2.1)	$	264.5

The Tender Offer and 2022 Senior Notes Redemption completed during the second quarter of 2021 resulted in a net loss on extinguishment of debt of $2.1 million, which included $1.5 million of accelerated unamortized deferred financing costs and $0.6 million of net premiums paid during the nine months ended September 30, 2021.

During the nine months ended September 30, 2020, we recorded a net gain on extinguishment of debt related to the Exchange Offers of $227.3 million, which was primarily comprised of the partial principal redemption of Old Notes and the debt discount associated with the issuance of the 2025 Senior Secured Notes. Also during the nine months ended September 30, 2020, we recorded net gains on the early extinguishment of portions of our 2022 Senior Notes and 2024 Senior Notes of $24.4 million and $12.9 million, respectively. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion of these transactions.

Income tax benefit


	For the Three Months Ended						For the Nine Months Ended
	September 30, 2021			June 30, 2021			September 30, 2021			September 30, 2020

	(in millions, except tax rate)
Income tax benefit	$	—		$	0.2		$	0.1		$	158.7
Effective tax rate	—		%	0.1		%	—		%	20.9		%

The effective tax benefit rate remained flat sequentially. The decrease in the effective tax benefit rate for the nine months ended September 30, 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 September 30, 2020, and the correlative effect on the valuation allowance balance 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.

Changes in federal income tax laws or enactment of proposed legislation to increase the corporate tax rate and eliminate or reduce certain oil and gas industry deductions could have a material impact on our effective tax rate and current tax expense. 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.

Sources of Cash

For the nine months ended September 30, 2021, cash flow from operating activities was sufficient to fund our capital program and we expect that to continue for the remainder of 2021. 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 cost carrying 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 half of 2021, three major credit rating agencies upgraded our credit ratings, citing our improved debt leverage and our expected ability to generate meaningful free cash flows, among other reasons. Additionally, one of these major credit rating agencies further upgraded our credit rating in conjunction with the issuance of our 2028 Senior Notes.

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. As of September 30, 2021, the remaining available borrowing capacity under our Credit Agreement provided $1.1 billion in liquidity. 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. Subsequent to September 30, 2021, the fall semi-annual borrowing base redetermination was completed, which reaffirmed both our borrowing base and aggregate lender commitments at $1.1 billion. The next scheduled borrowing base redetermination date is April 1, 2022. 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 October 21, 2021, September 30, 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 September 30, 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.

As of September 30, 2021, we had a zero balance on our revolving credit facility. Our daily weighted-average revolving credit facility debt balance was $128.2 million and $141.5 million for the three months ended September 30, 2021, and June 30, 2021, respectively, and $134.6 million and $142.2 million for the nine months ended September 30, 2021, and 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 details our weighted-average interest rates and our weighted-average borrowing rates for the periods presented:


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2021		June 30, 2021		September 30, 2021		September 30, 2020
Weighted-average interest rate	7.7	%	7.6	%	7.7	%	6.8	%
Weighted-average borrowing rate	6.9	%	6.7	%	6.7	%	6.0	%

Our weighted-average interest rate and our weighted-average borrowing rate remained flat sequentially, and increased YTD 2021-over-YTD 2020. The YTD 2021-over-YTD 2020 increase was primarily a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second quarter of 2020.

Our weighted-average interest rate and weighted-average borrowing rate are impacted by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rates are impacted by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect amounts associated with the repurchase 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. The 2021 Senior Secured Convertible Notes were retired upon maturity on July 1, 2021. After this date, the weighted-average interest rate is no longer impacted by the non-cash amortization of deferred financing costs or the non-cash amortization of the discount related to the 2021 Senior Secured Convertible Notes.

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 nine months ended September 30, 2021, we spent approximately $553.6 million on capital expenditures and on acquiring proved and unproved oil and gas properties. This amount differs from the costs incurred amount of $589.7 million for the nine months ended September 30, 2021, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, 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. Our 2021 total capital program budget is between $650.0 million and $675.0 million. We will continue to monitor the economic environment through the remainder of the year and adjust our activity level as warranted.

We may from time to time repurchase 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.

During the second quarter of 2021, we issued our 2028 Senior Notes and used the net cash proceeds of $392.8 million to repurchase $193.1 million and $172.3 million of outstanding principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, through the Tender Offer, and to redeem the remaining $19.3 million of 2022 Senior Notes then outstanding through the 2022 Senior Notes Redemption. We paid total consideration of $385.3 million, including net premiums, and paid $5.2 million of accrued interest related to the 2022 and 2024 Senior Notes. The 2021 Senior Secured Convertible Notes matured on July 1, 2021, and on that day, we used borrowings under our revolving credit facility to retire at par the outstanding principal amount of $65.5 million. During the nine months ended September 30, 2020, we repurchased $103.2 million in aggregate principal amount of our 2022 Senior Notes and $29.0 million in aggregate principal amount of our 2024 Senior Notes in open market transactions at a discount, for a total settlement amount, excluding accrued interest, of $94.2 million, resulting in a net gain on extinguishment of debt of $25.1 million and $37.3 million for the three and nine months ended September 30, 2020, respectively. During the second quarter of 2020, we completed the Exchange Offers, which resulted in the exchange of $718.9 million in aggregate principal amount of Old Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes. Further, in connection with the Private Exchange, we tendered $53.5 million in cash to certain holders of the 2021 Senior Unsecured Convertible Notes, which was borrowed against our revolving credit facility, and issued the Warrants. Please refer to Note 3 - Equity for additional discussion of the Warrants, including related impacts to equity and Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion of the debt transactions. 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 nine months ended September 30, 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 Nine Months Ended September 30, 2021, and 2020

The following tables present changes in cash flows between the nine months ended September 30, 2021, and 2020, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.

Operating activities


	For the Nine Months Ended September 30,				Amount Change Between Periods
	2021		2020

	(in millions)
Net cash provided by operating activities	$	730.1	$	534.1	$	196.0

Net cash provided by operating activities increased for the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to a $715.5 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, and a decrease in cash paid for G&A expense, LOE, and ad valorem taxes of $21.3 million, partially offset by an increase of $660.7 million in cash paid on settled derivative trades. 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 Nine Months Ended September 30,				Amount Change Between Periods
	2021		2020

	(in millions)
Net cash used in investing activities	$	(544.8)	$	(426.8)	$	(118.0)

Net cash used in investing activities increased for the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to increased capital expenditures of $130.5 million.

Financing activities


	For the Nine Months Ended September 30,				Amount Change Between Periods
	2021		2020

	(in millions)
Net cash used in financing activities	$	(155.6)	$	(107.3)	$	(48.3)

Net cash used in financing activities for the nine months ended September 30, 2021, related to $385.3 million of net cash paid, including net premiums to fund the Tender Offer and the 2022 Senior Notes Redemption, offset by net cash proceeds of $392.8 million from the issuance of our 2028 Senior Notes. Additionally, we paid $65.5 million to retire our 2021 Senior Secured Convertible Notes and had net repayments under our revolving credit facility of $93.0 million.

Net cash used in financing activities for the nine months ended September 30, 2020, related to $147.8 million of net cash paid to repurchase certain of our Senior Notes, and $12.9 million of debt issuance costs incurred upon the issuance of the 2025 Senior Secured Notes, partially offset by net borrowings under our revolving credit facility of $55.5 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 September 30, 2021, we had a zero 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 September 30, 2021, our outstanding principal amount of fixed-rate debt totaled $2.1 billion and we had no floating-rate debt outstanding. 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, 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 case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, 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 nine months ended September 30, 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 $130.1 million, $32.7 million, and $11.8 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2021, would have offset the declines in oil, gas, and NGL production revenue by approximately $133.6 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 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 $119.9 million, $31.7 million, and $12.0 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 nine months ended September 30, 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 income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020

	(in thousands)
Net income (loss) (GAAP)	$	85,593	$	(98,292)	$	(388,671)	$	(599,439)
Interest expense	40,861		41,519		120,268		123,385
Income tax benefit	(39)		(22,969)		(95)		(158,662)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	202,701		181,708		574,375		596,053
Exploration (1)	7,801		7,882		23,742		26,970
Impairment	8,750		8,750		26,250		1,007,263
Stock-based compensation expense	4,498		4,164		14,191		15,437
Net derivative (gain) loss	209,146		63,871		924,183		(314,269)
Derivative settlement gain (loss)	(213,555)		70,305		(480,262)		286,270

(Gain) loss on extinguishment of debt	(5)		(25,070)		2,139		(264,546)
Other, net	905		615		2,407		1,560
Adjusted EBITDAX (non-GAAP)	346,656		232,483		818,527		720,022
Interest expense	(40,861)		(41,519)		(120,268)		(123,385)
Income tax benefit	39		22,969		95		158,662
Exploration (1)	(7,801)		(7,882)		(23,742)		(26,970)
Amortization of debt discount and deferred financing costs	3,905		4,506		13,350		13,084
Deferred income taxes	(68)		(22,796)		(282)		(159,064)
Other, net	5,171		(2,991)		(9,708)		(7,854)
Net change in working capital	21,078		16,843		52,170		(40,411)
Net cash provided by operating activities (GAAP)	$	328,119	$	201,613	$	730,142	$	534,084

____________________________________________

(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 third 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 Company settled this matter on August 6, 2021. Please refer to Legal Proceedings in Part I, Item 3 of our 2020 Form 10-K for additional detail regarding this case.

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

The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended September 30, 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:


PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES
Period	Total Number of Shares Purchased (1)	Weighted Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Program (2)
07/01/2021 - 07/31/2021	99,319	$	24.63	—	3,072,184
08/01/2021 - 08/31/2021	7,224	$	17.91	—	3,072,184
09/01/2021 - 09/30/2021	112,919	$	19.10	—	3,072,184
Total:	219,462	$	21.56	—	3,072,184

___________________________________

(1) All shares purchased by us in the third quarter of 2021 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs issued under the terms of award agreements granted under the Equity Plan.

(2) In July 2006, our Board of Directors approved an increase in the number of shares of our 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 September 30, 2021, we did not repurchase any shares of our common stock, and as of the filing of this report, we 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)
4.1			Fifth Supplemental Indenture, dated as of June 23, 2021, by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on June 23, 2021, and incorporated herein by reference)
4.2			2022 Notes Supplemental Indenture, dated as of June 23, 2021, by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.3 to the registrant’s Current Report on Form 8-K filed on June 23, 2021, and incorporated herein by reference)
10.1†			SM Energy Company Employee Stock Purchase Plan, amended and restated effective as of April 5, 2021 (filed as Annex A in the registrant’s Definitive Proxy Statement on Schedule 14A, filed on April 16, 2021, and incorporated herein by reference)
10.2			Sixth Amendment to the Sixth Amended and Restated Credit Agreement, dated as of June 8, 2021, by and among the Company, Wells Fargo Bank, National Association, as Administrative Agent, and the institutions named therein as Lenders that are a party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 9, 2021, 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.
†			Exhibit constitutes a management contract or compensatory plan or agreement.

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

October 29, 2021	By:	/s/ HERBERT S. VOGEL
		Herbert S. Vogel
		President and Chief Executive Officer
		(Principal Executive Officer)

October 29, 2021	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

October 29, 2021	By:	/s/ PATRICK A. LYTLE
		Patrick A. Lytle
		Vice President - Chief Accounting Officer and Controller and Assistant Secretary
		(Principal Accounting Officer)