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, 2019~~March 31, 2020

☐ 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.)

(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 24, 2019,~~April 22, 2020, the registrant had ~~112,857,163~~112,988,682 shares of common stock outstanding.

TABLE OF CONTENTS



Item		Page
	Cautionary Information about Forward-Looking Statements	3

	Part I	34

Item 1.	Financial Statements (unaudited)	34

	Condensed Consolidated Balance Sheets ~~September 30, 2019,~~March 31, 2020, and December 31, ~~2018~~	3

	Condensed Consolidated Statements of Operations Three and Nine Months Ended September 30, 2019 ~~and 2018~~	4

	Condensed Consolidated ~~Statements~~Statement of ~~Comprehensive Income (Loss)~~Operations Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020, and 2019 ~~and 2018~~	5

	Condensed Consolidated Statements of ~~Stockholders’ Equity~~Comprehensive Loss ~~Continuous Quarterly Presentation~~Three Months Ended ~~September 30,~~March 31, 2020, and 2019 ~~and 2018~~	6

	Condensed Consolidated Statements of Stockholders’ Equity Three Months Ended March 31, 2020, and 2019	7

	Condensed Consolidated Statements of Cash Flows ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020, and 2019 ~~and 2018~~	8

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2624

Item 3.	Quantitative and Qualitative Disclosures About Market Risk (included within the content of Item 2)	4339

Item 4.	Controls and Procedures	4339

	Part II	4540

Item 1.	Legal Proceedings	4540

Item 1A.	Risk Factors	4540

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4543

Item 6.	Exhibits	4644

Cautionary Information about Forward-Looking Statements

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

the impacts of the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic on us, our financial condition, results of operations, future operations, business prospects, capital and financial resources, ability to service our debt, ability to access the capital markets, and our plans to address the foregoing;

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

the expected total production volumes for the fiscal year 2020;

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

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

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

possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;

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

future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;

cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;

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

plans, objectives, expectations and intentions; and


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

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in the Risk Factors section in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019 (“2019 Form 10-K”) and in the Risk Factors section in Part II, Item 1A of this report.

We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in forward-looking statements. The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share data)


	September 30, 2019			December 31, 2018			March 31, 2020				December 31, 2019
ASSETS
Current assets:										��
Cash and cash equivalents	$	10		$	77,965		$	15			$	10
Accounts receivable	146,211			167,536			143,311				184,732
Derivative assets	143,142			175,130			463,992				55,184
Prepaid expenses and other	21,751			8,632			17,842				12,708
Total current assets	311,114			429,263			625,160				252,634
Property and equipment (successful efforts method):
Proved oil and gas properties	8,143,381			7,278,362			8,043,156				8,934,020
Accumulated depletion, depreciation, and amortization	(3,953,181		)	(3,417,953		)	(4,389,103		)		(4,177,876		)
Unproved oil and gas properties	1,434,435			1,581,401			972,844				1,005,887
Wells in progress	325,230			295,529			224,509				118,769
Properties held for sale, net	—			5,280
Other property and equipment, net of accumulated depreciation of $64,971 and $57,102, respectively	79,278			88,546
Other property and equipment, net of accumulated depreciation of $64,815 and $64,032, respectively							36,932				72,848
Total property and equipment, net	6,029,143			5,831,165			4,888,338				5,953,648
Noncurrent assets:
Derivative assets	38,571			58,499			44,909				20,624
Other noncurrent assets	74,255			33,935			56,618				65,326
Total noncurrent assets	112,826			92,434			101,527				85,950
Total assets	$	6,453,083		$	6,352,862		$	5,615,025			$	6,292,232
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	431,440		$	403,199		$	359,406			$	402,008
Derivative liabilities	37,798			62,853			8,277				50,846
Other current liabilities	21,804			—			15,780				19,189
Total current liabilities	491,042			466,052			383,463				472,043
Noncurrent liabilities:
Revolving credit facility	129,000			—			72,000				122,500
Senior Notes, net of unamortized deferred financing costs	2,451,886			2,448,439			2,413,663				2,453,035
Senior Convertible Notes, net of unamortized discount and deferred financing costs	154,883			147,894			159,721				157,263
Asset retirement obligations	95,806			91,859			85,267				84,134
Deferred income taxes	217,469			223,278			93,918				189,386
Derivative liabilities	6,014			12,496			7,202				3,444
Other noncurrent liabilities	63,233			42,522			58,074				61,433
Total noncurrent liabilities	3,118,291			2,966,488			2,889,845				3,071,195

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,857,163 and 112,241,966 shares, respectively	1,129			1,122
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,988,682 and 112,987,952 shares, respectively							1,130				1,130
Additional paid-in capital	1,784,787			1,765,738			1,797,154				1,791,596
Retained earnings	1,069,642			1,165,842			554,562				967,587
Accumulated other comprehensive loss	(11,808		)	(12,380		)	(11,129		)		(11,319		)
Total stockholders’ equity	2,843,750			2,920,322			2,341,717				2,748,994
Total liabilities and stockholders’ equity	$	6,453,083		$	6,352,862		$	5,615,025			$	6,292,232

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,						For the Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	389,419		$	458,382		$	1,136,749		$	1,243,826		$	354,233		$	340,476
Net gain on divestiture activity	—			786			323			425,656			—			61
Other operating revenues	898			201			1,347			3,398			1,501			393
Total operating revenues and other income	390,317			459,369			1,138,419			1,672,880			355,734			340,930
Operating expenses:
Oil, gas, and NGL production expense	129,042			127,638			373,397			365,917			119,552			121,305
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	211,125			201,105			595,201			483,343			233,489			177,746
Exploration	11,626			13,061			33,851			40,844			11,349			11,348
Abandonment and impairment of unproved properties	6,337			9,055			25,092			26,615
Impairment													989,763			6,338
General and administrative	32,578			29,464			95,584			86,066			27,447			32,086
Net derivative (gain) loss	(100,889		)	178,026			(3,463		)	249,304			(545,340		)	177,081
Other operating expenses, net	1,021			9,664			422			14,219			566			335
Total operating expenses	290,840			568,013			1,120,084			1,266,308			836,826			526,239
Income (loss) from operations	99,477			(108,644		)	18,335			406,572
Loss from operations													(481,092		)	(185,309		)
Interest expense	(40,584		)	(38,111		)	(118,191		)	(122,850		)	(41,512		)	(37,980		)
Loss on extinguishment of debt	—			(26,722		)	—			(26,722		)
Other non-operating income (expense), net	(548		)	806			(1,427		)	3,017
Income (loss) before income taxes	58,345			(172,671		)	(101,283		)	260,017
Income tax (expense) benefit	(16,111		)	36,748			16,337			(61,342		)
Net income (loss)	$	42,234		$	(135,923	)	$	(84,946	)	$	198,675
Gain on extinguishment of debt													12,195			—
Other non-operating expense, net													(494		)	(317		)
Loss before income taxes													(510,903		)	(223,606		)
Income tax benefit													99,008			46,038
Net loss													$	(411,895	)	$	(177,568	)

Basic weighted-average common shares outstanding	112,804			112,107			112,441			111,836			113,009			112,252
Diluted weighted-average common shares outstanding	113,334			112,107			112,441			113,600			113,009			112,252
Basic net income (loss) per common share	$	0.37		$	(1.21	)	$	(0.76	)	$	1.78
Diluted net income (loss) per common share	$	0.37		$	(1.21	)	$	(0.76	)	$	1.75
Basic net loss per common share													$	(3.64	)	$	(1.58	)
Diluted net loss per common share													$	(3.64	)	$	(1.58	)
Dividends per common share	$	0.05		$	0.05		$	0.10		$	0.10		$	0.01		$	0.05

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)~~LOSS (UNAUDITED)

(in thousands)


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,					For the Three Months Ended March 31,
	2019		2018			2019			2018		2020			2019
Net income (loss)	$	42,234	$	(135,923	)	$	(84,946	)	$	198,675
Net loss											$	(411,895	)	$	(177,568	)
Other comprehensive income, net of tax:
Pension liability adjustment	190		263			572			721		190			263
Total other comprehensive income, net of tax	190		263			572			721		190			263
Total comprehensive income (loss)	$	42,424	$	(135,660	)	$	(84,374	)	$	199,396
Total comprehensive loss											$	(411,705	)	$	(177,305	)

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
	Shares	Amount					Retained Earnings
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


				Additional Paid-in Capital								Accumulated Other Comprehensive Loss				Total Stockholders’ Equity									Additional Paid-in Capital								Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Common Stock						Retained Earnings								Common Stock								Retained Earnings
	Shares	Amount					Retained Earnings			Accumulated Other Comprehensive Loss	Shares								Amount									Accumulated Other Comprehensive Loss
Balances, December 31, 2018	112,241,966	$	1,122			$	1,765,738				$		1,165,842						$	(12,380	)	$	Retained Earnings	2,920,322		112,241,966				$	1,122			$	1,765,738		$	1,165,842	$	(12,380	)	$	2,920,322
Net loss	—	—			—				(177,568		)		—			(177,568		)	—			—			—					(177,568		)		—		(177,568		)
Other comprehensive income	—	—		—				—					263				263			—			—			—				—				263			263
Cash dividends declared, $0.05 per share	—	—		—				(5,612		)		—				(5,612		)	—			—			—				(5,612		)		—			(5,612		)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	2,579	—		(18		)		—				—				(18		)	2,579			—			(18		)		—				—			(18		)
Stock-based compensation expense	—	—		5,838				—				—				5,838			—			—			5,838				—				—			5,838
Balances, March 31, 2019	112,244,545	$	1,122	$	1,771,558			$	982,662			$	(12,117	)		$	2,743,225		112,244,545			$	1,122		$	1,771,558			$	982,662			$	(12,117	)	$	2,743,225
Net income	—	—		—				50,388				—				50,388
Other comprehensive income	—	—		—				—				119				119
Issuance of common stock under Employee Stock Purchase Plan	184,079	2		1,957				—				—				1,959
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	290	—		(2		)		—				—				(2		)
Stock-based compensation expense	96,719	1		6,153				—				—				6,154
Other	—	—		(1		)		1				—				—
Balances, June 30, 2019	112,525,633	$	1,125	$	1,779,665			$	1,033,051			$	(11,998	)		$	2,801,843
Net income	—	—		—				42,234				—				42,234
Other comprehensive income	—	—		—				—				190				190
Cash dividends declared, $0.05 per share	—	—		—				(5,643		)		—				(5,643		)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	331,530	4		(1,644		)		—				—				(1,640		)
Stock-based compensation expense	—	—		6,766				—				—				6,766
Balances, September 30, 2019	112,857,163	$	1,129	$	1,784,787			$	1,069,642			$	(11,808	)		$	2,843,750

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

~~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, 2017 111,687,016
$ 1,117
$ 1,741,623
$ 665,657
$ (13,789 ) $ 2,394,608
Net income —
—
—
317,401
—
317,401
Other comprehensive income —
—
—
—
260
260
Cash dividends declared, $0.05 per share —
—
—
(5,584 ) —
(5,584 )
Stock-based compensation expense —
—
5,412
—
—
5,412
Cumulative effect of accounting change —
—
—
2,969
(2,969 ) —
Other —
—
—
1
(1 ) —
Balances, March 31, 2018 111,687,016
$ 1,117
$ 1,747,035
$ 980,444
$ (16,499 ) $ 2,712,097
Net income —
—
—
17,197
—
17,197
Other comprehensive income —
—
—
—
198
198
Issuance of common stock under Employee Stock Purchase Plan 100,249
1
1,880
—
—
1,881
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings 1,161
—
(10 ) —
—
(10 )
Stock-based compensation expense 58,572
—
5,264
—
—
5,264
Balances, June 30, 2018 111,846,998
$ 1,118
$ 1,754,169
$ 997,641
$ (16,301 ) $ 2,736,627
Net loss —
—
—
(135,923 ) —
(135,923 )
Other comprehensive income —
—
—
—
263
263
Cash dividends declared, $0.05 per share —
—
—
(5,607 ) —
(5,607 )
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings 290,584
3
(2,968 ) —
—
(2,965 )
Stock-based compensation expense —
—
7,004
—
—
7,004
Balances, September 30, 2018 112,137,582
$ 1,121
$ 1,758,205
$ 856,111
$ (16,038 ) $ 2,599,399

~~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,						For the Three Months Ended March 31,
	2019			2018			2020			2019
Cash flows from operating activities:
Net income (loss)	$	(84,946	)	$	198,675
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net loss							$	(411,895	)	$	(177,568	)
Adjustments to reconcile net loss to net cash provided by operating activities
Net gain on divestiture activity	(323		)	(425,656		)	—			(61		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	595,201			483,343			233,489			177,746
Abandonment and impairment of unproved properties	25,092			26,615
Impairment							989,763			6,338
Stock-based compensation expense	18,758			17,680			5,561			5,838
Net derivative (gain) loss	(3,463		)	249,304			(545,340		)	177,081
Derivative settlement gain (loss)	23,843			(101,911		)	73,437			(4,969		)
Amortization of debt discount and deferred financing costs	11,554			11,542			3,992			3,789
Loss on extinguishment of debt	—			26,722
Gain on extinguishment of debt							(12,195		)	—
Deferred income taxes	(13,620		)	60,672			(99,347		)	(47,003		)
Other, net	(2,291		)	(2,084		)	(816		)	(2,530		)
Net change in working capital	11,781			(3,725		)	(18,517		)	(20,159		)
Net cash provided by operating activities	581,586			541,177			218,132			118,502

Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties ⁽¹⁾	12,520			743,199
Net proceeds from the sale of oil and gas properties							—			6,114
Capital expenditures	(788,642		)	(1,032,588		)	(139,306		)	(249,340		)
Acquisition of proved and unproved oil and gas properties	(2,581		)	(24,571		)
Other, net							—			291
Net cash used in investing activities	(778,703		)	(313,960		)	(139,306		)	(242,935		)

Cash flows from financing activities:
Proceeds from credit facility	1,124,500			—
Repayment of credit facility	(995,500		)	—
Net proceeds from Senior Notes	—			492,079
Cash paid to repurchase Senior Notes, including premium	—			(844,984		)
Net proceeds from sale of common stock	1,959			1,881
Dividends paid	(5,612		)	(5,584		)
Proceeds from revolving credit facility							425,500			172,000
Repayment of revolving credit facility							(476,000		)	(125,500		)
Cash paid to repurchase 6.125% Senior Notes due 2022							(28,318		)	—
Other, net	(2,684		)	(7,746		)	(3		)	(18		)
Net cash provided by (used in) financing activities	122,663			(364,354		)	(78,821		)	46,482

Net change in cash, cash equivalents, and restricted cash	(74,454		)	(137,137		)	5			(77,951		)
Cash, cash equivalents, and restricted cash at beginning of period	77,965			313,943			10			77,965
Cash, cash equivalents, and restricted cash at end of period	$	3,511		$	176,806		$	15		$	14

Supplemental schedule of additional cash flow information and non-cash activities:

Operating activities:
Cash paid for interest, net of capitalized interest	$	(113,122	)	$	(124,435	)	$	(47,469	)	$	(39,957	)
Net cash paid for income taxes	$	(1,469	)	$	(9,085	)

Investing activities:
Changes in capital expenditure accruals and other	$	34,878		$	19,811
Increase in capital expenditure accruals and other							$	16,802		$	62,185

Supplemental non-cash investing activities:
Carrying value of properties exchanged	$	70,808		$	95,121		$	—		$	65,788
Supplemental non-cash financing activities:
Non-cash loss on extinguishment of debt, net	$	—		$	6,334

Reconciliation of cash, cash equivalents, and restricted cash:
Cash and cash equivalents	$	10		$	176,806
Restricted cash ⁽¹⁾	3,501			—
Cash, cash equivalents, and restricted cash at end of period	$	3,511		$	176,806


⁽¹⁾	As of September 30, 2019, a portion of net proceeds from the sale of oil and gas properties was restricted for future property acquisitions. Restricted cash is included in the other noncurrent assets line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”).

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

SM ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

Description of Operations

SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of ~~crude~~ oil, ~~and condensate, natural~~ gas, and ~~natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report)~~NGLs in ~~onshore North America.~~the State of Texas.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the ~~Company’s Annual Report on~~2019 Form ~~10-K for the year ended December 31, 2018 (the “2018 Form 10-K”).~~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, 2019,~~March 31, 2020, and through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying unaudited condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the ~~2018~~2019 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the ~~2018~~2019 Form 10-K.

Recently Issued Accounting Standards

In ~~February 2016,~~December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. ~~2016-02, Leases~~2019-12, Income Taxes (Topic ~~842), followed by other~~740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). ASU 2019-12 was issued to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting standard. The guidance is to be applied using a prospective method, excluding amendments related ~~ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02”~~to franchise taxes, which should be applied on either a retrospective basis for all periods presented or ~~“Topic 842”).~~a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company early adopted ASU ~~2016-02~~2019-12 on January 1, ~~2019, using~~2020, and there was no material impact on the ~~modified retrospective method.~~Company’s unaudited condensed consolidated financial statements or disclosures upon adoption.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 is effective for all entities as of March 12, 2020 through December 31, 2022. The Company ~~elected as part of its adoption to also use~~is evaluating the optional transition methodology whereby lease accounting for previously reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and practical expedients the Company has implemented in connection with the adoption ofoptions provided by ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources.

Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this guidance.2020-04. Please refer to Note 125 - ~~Leases~~Long-Term Debt for ~~additional discussion.~~discussion of the use of the London Interbank Offered Rate (“LIBOR”) in connection with borrowings under the Credit Agreement.

~~Other than as~~As disclosed in the ~~2018~~2019 Form 10-K, the Company adopted ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, and ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract on January 1, 2020. As expected, there was no material impact on the Company’s unaudited condensed consolidated financial statements or disclosures upon adoption of these ASUs.

There are no ASUs that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of ~~September 30, 2019,~~March 31, 2020, and 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. Following the divestiture of the Company’s remaining assets in the Rocky Mountain region during the first half of 2018, there has been no production revenue from this region after the second quarter of 2018. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) is reflective of the revenue generated from contracts with customers.

The ~~tables~~table below ~~present~~presents oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, and ~~2018:~~2019:

Midland Basin South Texas Total
Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30,
2019 2018 2019 2018 2019 2018
(in thousands)
Oil production revenue $ 277,361
$ 270,086
$ 15,496
$ 17,436
$ 292,857
$ 287,522
Gas production revenue 17,780
40,364
46,267
56,446
64,047
96,810
NGL production revenue 124
563
32,391
73,487
32,515
74,050
Total $ 295,265
$ 311,013
$ 94,154
$ 147,369
$ 389,419
$ 458,382
Relative percentage 76 % 68 % 24 % 32 % 100 % 100 %

~~Note: Amounts may not calculate due to rounding.~~

Midland Basin South Texas Rocky Mountain Total
Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018 2019 2018 2019 2018
(in thousands)
Oil production revenue $ 791,055
$ 703,516
$ 45,007
$ 56,365
$ —
$ 54,851
$ 836,062
$ 814,732
Gas production revenue 49,821
96,974
144,563
161,414
—
1,595
194,384
259,983
NGL production revenue 102
816
106,201
167,505
—
790
106,303
169,111
Total $ 840,978
$ 801,306
$ 295,771
$ 385,284
$ —
$ 57,236
$ 1,136,749
$ 1,243,826
Relative percentage 74 % 64 % 26 % 31 % — % 5 % 100 % 100 %



	Midland Basin						South Texas						Total
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019			2020			2019
	(in thousands)
Oil production revenue	$	276,136		$	225,247		$	15,557		$	13,814		$	291,693		$	239,061
Gas production revenue	11,334			15,592			29,376			49,521			40,710			65,113
NGL production revenue	58			21			21,772			36,281			21,830			36,302
Total	$	287,528		$	240,860		$	66,705		$	99,616		$	354,233		$	340,476
Relative percentage	81		%	71		%	19		%	29		%	100		%	100		%

Note: Amounts may not calculate due to rounding.

The Company recognizes oil, gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the purchaser, which ~~may differ~~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, while~~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 ~~control~~the transfer ~~are embedded in the price and effectively recorded as a reduction~~ of ~~oil, gas, and NGL production revenue.~~control. Please refer to Note 2 - Revenue from Contracts with Customers in the ~~2018~~2019 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL production revenue is generated.

Significant judgments made in applying the guidance in Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to purchasers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are 0 material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of ~~September 30, 2019,~~March 31, 2020, and December 31, ~~2018,~~2019, were ~~$106.3~~$62.0 million and ~~$107.2~~$146.3 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is

received from the purchaser. ~~Revenue recognized that related to performance obligations satisfied in prior reporting periods was immaterial for the three and nine months ended September 30, 2019, and 2018.~~

Note 3 - Divestitures, Assets Held for Sale, and Acquisitions

Divestitures

No material divestitures occurred during the first ~~nine months~~quarters of 2020 and 2019, and there were 0 assets classified as held for sale as of ~~September 30,~~March 31, 2020, or December 31, 2019.

~~On March 26, 2018,~~the Company divested approximately 112,000 net acres of its Powder River Basin assets (the “PRB Divestiture”) for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $490.8 million, subject to final purchase price adjustments, and recorded an estimated net gain of $410.6 million for the nine months ended September 30, 2018. After final purchase price adjustments, the Company received net divestiture proceeds of $492.2 million, and recorded a final net gain of $410.6 million related to these divested assets for the year ended December 31, 2018.

During the second quarter of 2018, the Company completed the divestitures of its remaining Williston Basin assets located in Divide County, North Dakota (the “Divide County Divestiture”) and its Halff East assets in the Midland Basin (the “Halff East Divestiture”), for combined net divestiture proceeds of $250.8 million, subject to final purchase price adjustments, and recorded a combined estimated net gain of $15.4 million for the nine months ended September 30, 2018. After final purchase price adjustments, the Company received net divestiture proceeds of $252.2 million, and recorded a final net gain of $15.4 million related to these divested assets for the year ended December 31, 2018.

Acquisitions

No material acquisitions or acreage trades of oil and gas properties occurred during the first quarter of 2020. During the first ~~nine months~~quarter of 2019, the Company completed several non-monetary acreage trades of primarily undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the exchange of approximately ~~2,100~~2,000 net acres, with $70.8 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with 0 gain or loss recognized. During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily undeveloped properties located in Howard and Martin Counties, Texas, which resulted in the exchange of approximately 2,650 net acres, with $95.1$65.8 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with 0 gain or loss recognized.

During the second quarter of 2018, the Company acquired approximately 720 net acres of unproved properties in Martin County, Texas, for $24.6 million. Under authoritative accounting guidance, this transaction was considered an asset acquisition. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired.

Note 4 - Income Taxes

The provision for income taxes for the three months ended March 31, 2020, and 2019, consisted of the following:



	For the Three Months Ended March 31,
	2020			2019
	(in thousands)
Current portion of income tax (expense) benefit:
Federal	$	—		$	—
State	(339		)	(965		)
Deferred portion of income tax benefit	99,347			47,003
Income tax benefit	$	99,008		$	46,038
Effective tax rate	19.4		%	20.6		%

Recorded income tax expense or benefit differs from the amounts that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax limitations on the compensation of ~~certain~~ covered individuals, changes in valuation allowances, and the cumulative impact of other smaller permanent differences. The quarterly rate can also be affected by the proportional impacts of forecasted net income or loss for each period presented, as reflected in the table ~~below.~~above.

~~The provision for income taxes for the three and nine months ended September 30, 2019, and 2018, consisted of the following:~~

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in thousands)
Current portion of income tax (expense) benefit:
Federal $ 3,826
$ —
$ 3,826
$ —
State (320 ) (85 ) (1,109 ) (670 )
Deferred portion of income tax (expense) benefit (19,617 ) 36,833
13,620
(60,672 )
Income tax (expense) benefit $ (16,111 ) $ 36,748
$ 16,337
$ (61,342 )
Effective tax rate 27.6 % 21.3 % 16.1 % 23.6 %

~~The~~A change in the Company’s effective tax rate ~~for the three months ended September 30, 2019,~~between reporting periods will generally reflect differences in estimating permanent differences compared with the same period in 2018, was primarily due to the differing effects of permanent items on income before income taxes for the three months ended September 30, 2019, compared to their impact on the loss before income taxes for the same period in 2018.

The change in the effective tax rate for the nine months ended September 30, 2019, compared with the same period in 2018, was primarily due to the differing effects of permanent items on the loss before income taxes for the nine months ended September 30, 2019, compared to their impact on income before income taxes for the same period in 2018. Additionally, the year-to-date 2018 rate was also impacted by the estimated highest marginal state tax rates due to changes in ~~the composition of~~forecasted net income or ~~loss from~~loss. Each quarter, the Company ~~activities, including divestitures, among multiple state~~evaluates its deferred tax ~~jurisdictions. Future periods are~~assets for potential realization, weighing both positive and negative evidence to determine, on a more likely than not ~~expected to reflect these differences as~~basis, the future utilization by asset and jurisdiction. When the significance of negative evidence outweighs the Company’s ~~current activities are occurring predominately in Texas.~~positive support of realization, a valuation allowance is recorded.

~~Subsequent to September 30, 2019,~~The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The primary feature of the CARES Act that the Company will benefit from is the acceleration of its refundable Alternative Minimum Tax (“AMT”) credits. On April 1, 2020, the Company filed an election to accelerate its ~~2018 federal income tax return claiming a $7.7~~remaining refundable AMT credits of $7.6 million ~~refund for a portion~~that are expected to be received during the second quarter of ~~its deferred AMT credit carryover.~~ 2020.

For all years before 2015, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

Note 5 - Long-Term Debt

Credit Agreement

On ~~September 19, 2019,~~April 29, 2020, the Company and its lenders entered into the ~~Second~~Third Amendment to the ~~Sixth Amended and Restated~~ Credit Agreement ~~which permitted the Company to enter into swap agreements with respect to the price of electricity in order to minimize exposure to electrical price volatility. As of September 30, 2019, the~~(“Third Amendment”). The Company’s ~~Sixth Amended and Restated~~ Credit Agreement ~~as amended (the “Credit Agreement”), provided~~provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 ~~billion,~~billion. Also on April 29, 2020, as a ~~borrowing base~~result of ~~$1.6 billion, and aggregate lender commitments of $1.2 billion. Subsequent to September 30, 2019,~~ the ~~Company and its lenders completed the~~regular semi-annual borrowing base redetermination, ~~which reaffirmed~~ the ~~Company’s~~ borrowing base and aggregate lender commitments ~~at existing levels.~~were both reduced to $1.1 billion due to a decrease in the value of proved reserves driven by decreased commodity pricing. The Third Amendment permits the Company to incur second lien debt of up to $900.0 million (“Permitted Lien Debt”) prior to the next scheduled ~~borrowing base~~ redetermination date ~~is April~~of October 1, ~~2020.~~2020, provided that all principal amounts of such debt are used to redeem unsecured senior debt of the Company for less than or equal to par value. Additionally, the Third Amendment reduces the limit on the amount of dividends that the Company may declare and pay on an annual basis from $50.0 million to $12.0 million. The Third Amendment also amends certain other covenants of the Company in the Credit Agreement.

The Credit Agreement is scheduled to mature on September 28, ~~2023. The~~2023, except that, pursuant to the Third Amendment, upon the Company’s incurrence of Permitted Lien Debt to redeem the 6.125% Senior Notes due 2022 (“2022 Senior Notes”), the maturity date under the Credit Agreement will be July 2, 2023. Without regard to which maturity date is in effect, the maturity date could ~~however,~~ occur earlier on August 16, 2022, if the Company has not completed certain repurchase, redemption, or refinancing activities associated with its ~~6.125%~~2022 Senior Notes, ~~due 2022 (“2022 Senior Notes”),~~and does not have certain unused availability for borrowing under the Credit Agreement, as outlined in the Credit ~~Agreement.~~

Agreement and the Third Amendment. The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement and was in compliance with all such covenants as of ~~September 30, 2019,~~March 31, 2020, and through the filing of this report. ~~Please refer to~~ ~~Note 5 - Long-Term Debt~~ ~~in the 2018 Form 10-K for additional detail on the terms of the Company’s Credit Agreement.~~

Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit ~~Agreement~~Agreement. The borrowing base utilization grid was amended by the Third Amendment as presented in the table below. Please refer to Note 5 - Long-Term Debt in the ~~Company’s 2018~~2019 Form ~~10-K.~~10-K for the utilization grid in effect prior to the Third Amendment. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at ~~the London Interbank Offered Rate,~~LIBOR, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations. Please refer to Note 5 - Long-Term Debt in the 2019 Form 10-K for additional detail on the terms of the Company’s Credit Agreement.



Borrowing Base Utilization Percentage	<25%		≥25% <50%		≥50% <75%		≥75% <90%		≥90%
Eurodollar Loans ⁽¹⁾	1.750	%	2.000	%	2.500	%	2.750	%	3.000	%
ABR Loans or Swingline Loans	0.750	%	1.000	%	1.500	%	1.750	%	2.000	%
Commitment Fee Rate	0.375	%	0.375	%	0.500	%	0.500	%	0.500	%

____________________________________________



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

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of ~~October 24, 2019, September 30, 2019,~~filing on April 29, 2020, March 31, 2020, and December 31, ~~2018:~~2019:


	As of October 24, 2019		As of September 30, 2019		As of December 31, 2018		As of filing on April 29, 2020		As of March 31, 2020		As of December 31, 2019
	(in thousands)						(in thousands)
Revolving credit facility ⁽¹⁾	$	143,000	$	129,000	$	—	$	93,500	$	72,000	$	122,500
Letters of credit ⁽²⁾	—		—		200		—		—		—
Available borrowing capacity	1,057,000		1,071,000		999,800		1,006,500		1,128,000		1,077,500
Total aggregate lender commitment amount	$	1,200,000	$	1,200,000	$	1,000,000	$	1,100,000	$	1,200,000	$	1,200,000

____________________________________________

⁽¹⁾

Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled ~~$6.3~~$5.5 million and ~~$6.4~~$5.9 million as of ~~September 30, 2019,~~March 31, 2020, and December 31, ~~2018,~~2019, 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 credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018, was released during the three months ended March 31, 2019.

Senior Notes

As of September 30, 2019, the Company’s senior notes consisted of 6.125% Senior Notes due 2022, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, 6.75% Senior Notes due 2026, and 6.625% Senior Notes due 2027 (“2027 Senior Notes”, and all senior notes collectively referred to as the “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of ~~September 30, 2019~~March 31, 2020, and December 31, ~~2018~~2019, consisted of the following:


	As of September 30, 2019						As of December 31, 2018						As of March 31, 2020						As of December 31, 2019
	Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net of Unamortized Deferred Financing Costs		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net of Unamortized Deferred Financing Costs		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net of Unamortized Deferred Financing Costs		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net of Unamortized Deferred Financing Costs
	(in thousands)												(in thousands)
6.125% Senior Notes due 2022	$	476,796	$	3,170	$	473,626	$	476,796	$	3,921	$	472,875	$	436,047	$	2,442	$	433,605	$	476,796	$	2,920	$	473,876
5.0% Senior Notes due 2024	500,000		3,996		496,004		500,000		4,688		495,312		500,000		3,535		496,465		500,000		3,766		496,234
5.625% Senior Notes due 2025	500,000		5,130		494,870		500,000		5,808		494,192		500,000		4,677		495,323		500,000		4,903		495,097
6.75% Senior Notes due 2026	500,000		5,780		494,220		500,000		6,407		493,593		500,000		5,362		494,638		500,000		5,571		494,429
6.625% Senior Notes due 2027	500,000		6,834		493,166		500,000		7,533		492,467		500,000		6,368		493,632		500,000		6,601		493,399
Total	$	2,476,796	$	24,910	$	2,451,886	$	2,476,796	$	28,357	$	2,448,439	$	2,436,047	$	22,384	$	2,413,663	$	2,476,796	$	23,761	$	2,453,035

The ~~Senior Notes~~senior notes listed above (collectively referred to as the “Senior Notes”) are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any

future subordinated debt. There are no subsidiary guarantors of any of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes and was in compliance with all ~~such~~ covenants as of ~~September 30, 2019,~~March 31, 2020, and through the filing of this report. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.

On July 16, 2018, the Company redeemed its 6.50% Senior Notes due 2021 (“2021 Senior Notes”) which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 2027 Senior Notes, which resulted in the receipt of net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. The proceeds received from the issuance of the 2027 Senior Notes were used to fund the cash tender offer and redemption of all of the Company’s 6.50% Senior Notes due 2023 (“2023 Senior Notes”) and a portion of its 2022 Senior Notes during the third quarter of 2018. The Company paid total consideration, including accrued interest, of $497.8 million to complete these transactions. As a result of the redemption of the 2021 Senior Notes, and the cash tender offer and redemption of all of the 2023 Senior Notes and a portion of the 2022 Senior Notes, the Company recorded a combined loss on extinguishment of debt of $26.7 million for the quarter ended September 30, 2018. This amount included combined premiums paid of $20.4 million and $6.3 million of accelerated unamortized deferred financing costs for the redemption. Please refer to Note 5 - Long-Term Debt in ~~Part II, Item 8 of our 2018~~the 2019 Form 10-K for additional ~~discussion.~~detail on the Company’s Senior Notes.

During the first quarter of 2020, the Company repurchased a total of $40.7 million in aggregate principal amount of its 2022 Senior Notes in open market transactions for a total settlement amount, excluding accrued interest, of $28.3 million. In connection with the repurchase, the Company recorded a gain on extinguishment of debt of $12.2 million for the three months ended March 31, 2020. This amount included discounts realized upon repurchase of $12.4 million partially offset by approximately $235,000 of accelerated unamortized deferred financing costs. The Company canceled all repurchased 2022 Senior Notes upon cash settlement.

Senior Convertible Notes

~~The~~As of March 31, 2020, the Company’s senior convertible notes ~~consist~~consisted of $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. Please refer to Note 5 - Long-Term Debt in the ~~2018~~2019 Form 10-K for additional detail on the Company’s Senior Convertible Notes and associated capped call transactions.

The Senior Convertible Notes were not convertible at the option of holders as of ~~September 30, 2019,~~March 31, 2020, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of ~~September 30, 2019,~~March 31, 2020, did not exceed the principal amount. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled ~~$2.8~~$2.9 million and ~~$2.6~~$2.7 million for the three months ended ~~September 30,~~March 31, 2020, and 2019, ~~and 2018, respectively, and totaled $8.2 million and $7.8 million for the nine months ended September 30, 2019, and 2018,~~ respectively.

There have been no changes to the initial net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets since issuance. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of ~~September 30, 2019,~~March 31, 2020, and December 31, ~~2018,~~2019, consisted of the following:


	As of September 30, 2019			As of December 31, 2018			As of March 31, 2020			As of December 31, 2019
	(in thousands)						(in thousands)
Principal amount of Senior Convertible Notes	$	172,500		$	172,500		$	172,500		$	172,500
Unamortized debt discount	(16,012		)	(22,313		)	(11,633		)	(13,861		)
Unamortized deferred financing costs	(1,605		)	(2,293		)	(1,146		)	(1,376		)
Senior Convertible Notes, net of unamortized discount and deferred financing costs	$	154,883		$	147,894		$	159,721		$	157,263

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all ~~such~~ covenants as of ~~September 30, 2019,~~March 31, 2020, and through the filing of this report.

Capitalized Interest

Capitalized interest costs for the three months ended ~~September 30,~~March 31, 2020, and 2019, ~~and 2018, were $4.2~~totaled $2.7 million and ~~$5.2 million, respectively, and for the nine months ended September 30, 2019, and 2018, were $14.1 million and $15.7~~$4.9 million, respectively. The amount of interest the Company capitalizes generally fluctuates based on the amount borrowed, the Company’s capital program, and the timing and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred.

Note 6 - Commitments and Contingencies

Commitments

Other than those items discussed below, there have been no changes in commitments through the filing of this report that differ materially from those disclosed in the ~~2018~~2019 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the ~~2018~~2019 Form 10-K for additional discussion of the Company’s commitments.

~~Delivery and Purchase Commitments.~~ ~~During the second quarter of 2019,~~Subsequent to March 31, 2020, the Company ~~executed an amendment to~~amended certain of its ~~existing sand sourcing agreement that created certain commitments~~drilling rig contracts resulting in the reduction of day rates and potential ~~penalties that vary based on~~early termination fees and the ~~amount~~extension of ~~sand the Company uses in well completions occurring in a particular area. This amended sand sourcing agreement expires on December 31, 2023.~~contract terms. As of ~~September 30, 2019, potential penalties under~~the filing of this ~~sand sourcing agreement range from 0 to a maximum of $10.0 million. The Company does not expect to incur material penalties with regard to this agreement.~~

~~Drilling Rig and Completion Service Contracts.~~ ~~The Company entered into new and amended drilling rig and well completion service contracts during the nine months ended September 30, 2019. As of September 30, 2019,~~report, the Company’s drilling rig ~~and completion service contract~~ commitments totaled ~~$57.1~~$22.3 million. If all of these contracts were terminated as of ~~September 30, 2019,~~the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay ~~$38.1~~$12.9 million in early termination fees. Excluded from these amounts are variable commitments and potential penalties determined by the number of completion crews the Company has in operation in a particular area under a completion service arrangement. As of September 30, 2019, potential penalties under this completion service arrangement, which expires on December 31, 2023, range from 0 to a maximum of $14.3 million. The Company does not expect to incur material penalties with regard to its drilling rig ~~and completion service~~ contracts.

~~Electrical Power Purchase Contracts.~~ ~~During the second quarter of 2019,~~

Subsequent to March 31, 2020, the Company entered into ~~a fixed price contract for the purchase of electrical power~~an agreement that ~~increased the purchase commitment under an~~included minimum drilling and completion footage requirements on certain existing ~~agreement. As of September 30, 2019,~~leases. If these minimum requirements are not satisfied by March 31, 2021, the Company ~~had~~would be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. The liquidated damages could range from 0 to a ~~commitment~~maximum of $42.0 million, with the maximum exposure assuming no development activity occurred prior to ~~purchase electrical power through 2027 with a total remaining obligation of $55.1 million.~~March 31, 2021. As of the filing of this report, the Company expects to meet its obligations under this ~~commitment.~~agreement.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Note 7 - Compensation Plans

Equity Incentive Compensation Plan

As of ~~September 30, 2019, 4.1~~March 31, 2020, 4.5 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”).

Performance Share Units

The Company grants performance share units (“PSUs”) to eligible employees as part of its ~~long-term equity incentive compensation program.~~Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0 to 2 times the number of PSUs awarded and is determined based on certain ~~settlement~~performance criteria over a three-year performance period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Equity Plan.

For PSUs ~~that were~~ granted in ~~2016 and~~ 2017, which the Company has determined to be equity awards, the settlement criteria ~~included~~include a combination of the Company’s Total Shareholder Return (“TSR”) on an absolute basis, and the Company’s TSR relative to the TSR of certain peer companies over the associated three-year performance period. The fair value of the PSUs granted in ~~2016 and~~ 2017 was measured on the ~~applicable~~ grant ~~dates~~date using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). As these awards depend entirely on market-based settlement criteria, the associated compensation expense is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards.

For PSUs granted in 2018 and 2019, the settlement criteria ~~included~~include a combination of the Company’s TSR relative to the TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance measures, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair value of the PSUs granted in 2018 and 2019 was measured on the applicable grant dates using the GBM Model, with the assumption that the associated CRTCI performance condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs granted in 2018 and 2019 is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected CRTCI performance relative to the applicable peer companies.

The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was ~~$2.9~~$2.6 million and ~~$3.0~~$2.8 million for the three months ended ~~September 30,~~March 31, 2020, and 2019, ~~and 2018, respectively, and was $8.6 million and $7.7 million for the nine months ended September 30, 2019, and 2018,~~ respectively. As of ~~September 30, 2019,~~March 31, 2020, there was ~~$19.7~~$12.9 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2022.

~~A summary of~~ There have been no material changes to the ~~status~~outstanding and ~~activity of~~ non-vested PSUs ~~for~~during the ~~nine~~three months ended ~~September 30, 2019, is presented in the following table:~~

PSUs ⁽¹⁾
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year 1,711,259
$ 20.68
Granted 793,125
$ 12.80
Vested (346,021 ) $ 26.31
Forfeited (40,999 ) $ 17.96
Non-vested at end of quarter 2,117,364
$ 16.86


⁽¹⁾	~~The number of awards assumes a multiplier of 1. The final number of shares of common stock issued may vary depending on the three-year performance multiplier which ranges from 0 to 2.~~

During the nine months ended September 30, 2019, the Company issued 793,125 PSUs with a grant date fair value of $10.2 million. In addition to the settlement criteria described above, the 2019 Performance Share Unit Award Agreement also stipulates that if either the Company’s absolute TSR, or absolute CRTCI, is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs shall be capped at 1 times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to the peer group. During the nine months ended September 30, 2019, the Company settled PSUs that were granted in 2016, with 0 shares issued upon settlement because the grant settled at a 0 multiplier.March 31, 2020.

Employee Restricted Stock Units

The Company grants restricted stock units (“RSUs”) to eligible persons as part of its ~~long-term equity incentive compensation program.~~Equity Plan. Each RSU represents a right to receive 1 share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. ~~Compensation expense for~~ RSUs ~~is recognized within general and administrative expense and~~

~~exploration expense over the vesting periods~~generally vest one-third of the ~~respective awards. RSUs granted to employees generally vest one-third~~total grant on each anniversary date of the grant over a three-year vesting period or upon other triggering events as set forth in the Equity Plan.

The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for employee RSUs was ~~$2.9~~$2.6 million and ~~$3.0~~$2.7 million for the

three months ended ~~September 30,~~March 31, 2020, and 2019, ~~and 2018, respectively, and was $8.4 million and $8.0 million for the nine months ended September 30, 2019, and 2018,~~ respectively. As of ~~September 30, 2019,~~March 31, 2020, there was ~~$21.4~~$13.6 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2022.

~~A summary of~~ There have been no material changes to the ~~status~~outstanding and ~~activity of~~ non-vested RSUs ~~granted to employees for~~during the ~~nine~~three months ended ~~September 30, 2019, is presented~~March 31, 2020.

Please refer to Note 7 - Compensation Plans in the ~~following table:~~

RSUs Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year 1,243,163
$ 21.50
Granted 978,932
$ 12.36
Vested (466,535 ) $ 21.93
Forfeited (111,188 ) $ 19.94
Non-vested at end of quarter 1,644,372
$ 16.04

~~During the nine months ended September 30,~~ 2019 the Company granted 978,932 RSUs with a grant date fair value of $12.1 million. Also, during the nine months ended September 30, 2019, the Company settled 466,535 RSUs that related to awards granted in previous years. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as providedForm 10-K for ~~in the Equity Plan and award agreements. As a result, the Company issued 334,399 net shares of common stock upon settlement of the awards.~~

~~Director Shares~~

During the second quarters of 2019, and 2018, the Company issued 96,719 and 58,572 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. Shares issued during the second quarter of 2019 will fully vestadditional detail on ~~December 31, 2019. Shares issued during the second quarter of 2018 fully vested on December 31, 2018. The Company did not issue any director shares during the third quarters of 2019, or 2018.~~

~~Employee Stock Purchase Plan~~

~~Under~~ the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. There were 184,079 and 100,249 shares issued under the ESPP during the nine months ended September 30, 2019, and 2018, respectively. Total proceeds to the Company for the issuance of these shares was $2.0 million and $1.9 million for the nine months ended September 30, 2019, and 2018, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.Equity Plan.

Note 8 - Pension Benefits

Pension Plans

The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen will continue to earn benefits.

Components of Net Periodic Benefit Cost for the Pension Plans


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(in thousands)												(in thousands)
Components of net periodic benefit cost:
Service cost	$	1,395		$	1,683		$	4,186		$	5,048		$	1,395		$	1,683
Interest cost	699			657			2,094			1,967			698			656
Expected return on plan assets that reduces periodic pension benefit cost	(393		)	(466		)	(1,180		)	(1,397		)	(393		)	(466		)
Amortization of prior service cost	4			4			13			13			4			4
Amortization of net actuarial loss	239			331			718			995			240			332
Net periodic benefit cost	$	1,944		$	2,209		$	5,831		$	6,626		$	1,944		$	2,209

Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. The service cost component of net periodic benefit cost for the Pension Plans is presented as an operating expense within the general and administrative and exploration expense line items on the accompanying statements of operations while the other components of net periodic benefit cost for the Pension Plans are presented as non-operating expenses within the other non-operating ~~income (expense),~~expense, net line item on the accompanying statements of operations.

Contributions

As of the filing of this report, the Company has contributed ~~$7.2~~$3.3 million to the Qualified Pension Plan in ~~2019 and does not expect to make additional contributions for the remainder of 2019.~~2020.

Note 9 - Earnings Per Share

Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020, and 2019, ~~and 2018, and~~ therefore, the Senior Convertible Notes had no dilutive impact. Please refer to Note 9 - Earnings Per Share in the ~~2018~~2019 Form 10-K for additional detail on these potentially dilutive securities.

When the Company recognizes a net loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average anti-dilutive securities for the periods presented:

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in thousands)
Anti-dilutive —
2,433
707
—



	For the Three Months Ended March 31,
	2020	2019
	(in thousands)
Anti-dilutive	1,219	781

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


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,					For the Three Months Ended March 31,
	2019		2018			2019			2018		2020			2019
	(in thousands, except per share data)										(in thousands, except per share data)
Net income (loss)	$	42,234	$	(135,923	)	$	(84,946	)	$	198,675
Net loss											$	(411,895	)	$	(177,568	)

Basic weighted-average common shares outstanding	112,804		112,107			112,441			111,836		113,009			112,252
Dilutive effect of non-vested RSUs and contingent PSUs	530		—			—			1,764		—			—
Diluted weighted-average common shares outstanding	113,334		112,107			112,441			113,600		113,009			112,252

Basic net income (loss) per common share	$	0.37	$	(1.21	)	$	(0.76	)	$	1.78
Diluted net income (loss) per common share	$	0.37	$	(1.21	)	$	(0.76	)	$	1.75
Basic net loss per common share											$	(3.64	)	$	(1.58	)
Diluted net loss per common share											$	(3.64	)	$	(1.58	)

Note 10 - Derivative Financial Instruments

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

The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of ~~September 30, 2019,~~March 31, 2020, all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil ~~and gas~~ production, and swap arrangements for gas and NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between ~~NYMEX~~New York Mercantile Exchange (“NYMEX”) WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices.

As of ~~September 30, 2019,~~March 31, 2020, the Company had commodity derivative contracts outstanding through the fourth quarter of 2022 as summarized in the tables below.

Oil Swaps


Contract Period	NYMEX WTI Volumes	Weighted-Average Contract Price		NYMEX WTI Volumes	Weighted-Average Contract Price
	(MBbl)	(per Bbl)		(MBbl)	(per Bbl)
Fourth quarter 2019	1,685	$	61.38
2020	7,441	$	59.64
Second quarter 2020				2,838	$	58.81
Third quarter 2020				3,361	$	56.43
Fourth quarter 2020				4,397	$	57.03
2021				2,085	$	45.70
Total	9,126			12,681

Oil Collars

Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price
(MBbl) (per Bbl) (per Bbl)
Fourth quarter 2019 3,168
$ 50.54
$ 62.49
2020 6,010
$ 55.00
$ 62.95
2021 329
$ 55.00
$ 56.70
Total 9,507



Contract Period	NYMEX WTI Volumes	Weighted-Average Floor Price		Weighted-Average Ceiling Price
	(MBbl)	(per Bbl)		(per Bbl)
Second quarter 2020	1,881	$	55.00	$	62.17
Third quarter 2020	1,252	$	55.00	$	62.90
Fourth quarter 2020	610	$	55.00	$	61.90
2021	329	$	55.00	$	56.70
Total	4,072

Oil Basis Swaps


Contract Period	WTI Midland-NYMEX WTI Volumes	Weighted-Average Contract Price ⁽¹⁾			NYMEX WTI-ICE Brent Volumes	Weighted-Average Contract Price ⁽²⁾			WTI Midland-NYMEX WTI Volumes	Weighted-Average Contract Price ⁽¹⁾			NYMEX WTI-ICE Brent Volumes	Weighted-Average Contract Price ⁽²⁾
	(MBbl)	(per Bbl)			(MBbl)	(per Bbl)			(MBbl)	(per Bbl)			(MBbl)	(per Bbl)
Fourth quarter 2019	3,338	$	(2.87	)	—	$	—
2020	14,090	$	(0.73	)	2,750	$	(8.03	)
Second quarter 2020									3,637	$	(0.62	)	910	$	(8.06	)
Third quarter 2020									3,607	$	(0.62	)	920	$	(8.01	)
Fourth quarter 2020									4,087	$	(0.38	)	920	$	(8.01	)
2021	3,708	$	0.33		3,650	$	(7.86	)	11,527	$	0.87		3,650	$	(7.86	)
2022	—	$	—		3,650	$	(7.78	)	9,500	$	1.15		3,650	$	(7.78	)
Total	21,136				10,050				32,358				10,050


⁽¹⁾	Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).


⁽²⁾	Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).

Gas Swaps


Contract Period	IF HSC Volumes	Weighted-Average Contract Price		WAHA Volumes	Weighted-Average Contract Price		IF HSC Volumes	Weighted-Average Contract Price		WAHA Volumes	Weighted-Average Contract Price
	(BBtu)	(per MMBtu)		(BBtu)	(per MMBtu)		(BBtu)	(per MMBtu)		(BBtu)	(per MMBtu)
Fourth quarter 2019	14,433	$	2.88	2,962	$	1.75
2020	11,773	$	2.87	4,977	$	1.70
Second quarter 2020							4,160	$	2.20	3,592	$	0.63
Third quarter 2020							4,493	$	2.41	4,294	$	1.07
Fourth quarter 2020							6,994	$	2.32	4,516	$	1.20
2021							28,621	$	2.29	17,533	$	1.45
2022							6,104	$	2.23	—	$	—
Total ⁽¹⁾	26,206			7,939			50,372			29,935

____________________________________________


⁽¹⁾	The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of ~~September 30, 2019,~~March 31, 2020, WAHA volumes were comprised of 5681 percent IF WAHA and 4419 percent GD WAHA.

~~Gas Collars~~NGL Swaps

Contract Period IF HSC Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price
(BBtu) (per MMBtu) (per MMBtu)
Fourth quarter 2019 4,818
$ 2.50
$ 2.83
Total 4,818

~~NGL Swaps~~


	OPIS Ethane Purity Mont Belvieu			OPIS Propane Mont Belvieu Non-TET			OPIS Normal Butane Mont Belvieu Non-TET			OPIS Isobutane Mont Belvieu Non-TET			OPIS Natural Gasoline Mont Belvieu Non-TET			OPIS Ethane Purity Mont Belvieu			OPIS Propane Mont Belvieu Non-TET
Contract Period	Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price
	(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)
Fourth quarter 2019	896	$	12.36	660	$	31.60	39	$	35.64	29	$	35.70	50	$	50.93
2020	711	$	11.38	1,187	$	23.58	—	$	—	—	$	—	—	$	—
Second quarter 2020																264	$	11.13	382	$	22.34
Third quarter 2020																—	$	—	409	$	22.33
Fourth quarter 2020																—	$	—	466	$	22.29
Total	1,607			1,847			39			29			50			264			1,257

Commodity Derivative Contracts Entered Into Subsequent to ~~September 30, 2019~~March 31, 2020

Subsequent to ~~September 30, 2019,~~March 31, 2020, the Company entered into the following commodity derivative contracts:

fixed price NYMEX WTI oil swap contracts for ~~the third quarter of 2020~~2021 for a total of ~~0.9~~5.5 MMBbl of oil production at a weighted-average contract price of ~~$51.61~~$37.57 per Bbl;

fixed price IF HSC gas swap contracts for ~~the second through fourth quarters of 2020~~2021 for a total of ~~9,725~~6,197 BBtu of gas production at a weighted-average contract price of ~~$2.28~~$2.42 per MMBtu;

fixed price IF WAHA gas swap contracts ~~for 2020 and~~through the fourth quarter of 2021 for a total of ~~12,229~~2,437 BBtu of gas production at a weighted-average contract price of ~~$1.06~~$1.57 per MMBtu; and

~~fixed price OPIS Propane Mont Belvieu Non-TET~~crude oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) for the second quarter of 2020 through the fourth quarter of 2021 for a total of ~~0.5~~6.8 MMBbl of ~~propane~~oil production, atin which the Company pays the periodic variable Roll Differential and receives a weighted-average ~~contract~~fixed price of ~~$19.27~~$(1.24) per ~~Bbl.~~Bbl; the weighted average price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the commodity derivative contracts was a net asset of ~~$137.9~~$493.4 million and ~~$158.3~~$21.5 million as of ~~September 30, 2019,~~March 31, 2020, and December 31, ~~2018,~~2019, respectively.

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


	As of September 30, 2019		As of December 31, 2018		As of March 31, 2020		As of December 31, 2019
	(in thousands)				(in thousands)
Derivative assets:
Current assets	$	143,142	$	175,130	$	463,992	$	55,184
Noncurrent assets	38,571		58,499		44,909		20,624
Total derivative assets	$	181,713	$	233,629	$	508,901	$	75,808
Derivative liabilities:
Current liabilities	$	37,798	$	62,853	$	8,277	$	50,846
Noncurrent liabilities	6,014		12,496		7,202		3,444
Total derivative liabilities	$	43,812	$	75,349	$	15,479	$	54,290

Offsetting of Derivative Assets and Liabilities

As of ~~September 30, 2019,~~March 31, 2020, and December 31, ~~2018,~~2019, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:


	Derivative Assets						Derivative Liabilities
	As of						As of						Derivative Assets as of						Derivative Liabilities as of
	September 30, 2019			December 31, 2018			September 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019			March 31, 2020			December 31, 2019
	(in thousands)												(in thousands)
Gross amounts presented in the accompanying balance sheets	$	181,713		$	233,629		$	(43,812	)	$	(75,349	)	$	508,901		$	75,808		$	(15,479	)	$	(54,290	)
Amounts not offset in the accompanying balance sheets	(43,812		)	(56,041		)	43,812			56,041			(15,479		)	(35,075		)	15,479			35,075
Net amounts	$	137,901		$	177,588		$	—		$	(19,308	)	$	493,422		$	40,733		$	—		$	(19,215	)

The following table summarizes the commodity components of the derivative settlement (gain) loss, as well as the components of the net derivative (gain) loss line item presented in the accompanying statements of operations:


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,						For the Three Months Ended March 31,
	2019			2018		2019			2018			2020			2019
	(in thousands)											(in thousands)
Derivative settlement (gain) loss:
Oil contracts	$	2,246		$	16,798	$	14,304		$	61,976		$	(53,582	)	$	1,369
Gas contracts	(12,210		)	802		(13,744		)	(4,851		)	(14,625		)	4,134
NGL contracts	(14,758		)	23,118		(24,403		)	44,786			(5,230		)	(534		)
Total derivative settlement (gain) loss	$	(24,722	)	$	40,718	$	(23,843	)	$	101,911		$	(73,437	)	$	4,969

Net derivative (gain) loss:
Oil contracts	$	(83,984	)	$	110,413	$	67,261		$	146,781		$	(542,540	)	$	185,797
Gas contracts	(4,228		)	4,309		(36,337		)	21,299			6,728			(6,113		)
NGL contracts	(12,677		)	63,304		(34,387		)	81,224			(9,528		)	(2,603		)
Total net derivative (gain) loss	$	(100,889	)	$	178,026	$	(3,463	)	$	249,304		$	(545,340	)	$	177,081

Credit Related Contingent Features

As of ~~September 30, 2019,~~March 31, 2020, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

Note 11 - Fair Value Measurements

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

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

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

Level 3 – significant inputs to the valuation model are unobservable

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of ~~September 30, 2019:~~March 31, 2020:


	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in thousands)						(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	181,713	$	—	$	—	$	508,901	$	—
Total property and equipment, net⁽²⁾							$	—	$	—	$	380,734
Liabilities:
Derivatives ⁽¹⁾	$	—	$	43,812	$	—	$	—	$	15,479	$	—

__________________________________________


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


⁽²⁾	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

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 ~~were~~are classified within the fair value hierarchy as of December 31, ~~2018:~~2019:


	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in thousands)						(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	233,629	$	—	$	—	$	75,808	$	—
Liabilities:
Derivatives⁽¹⁾	$	—	$	75,349	$	—	$	—	$	54,290	$	—

____________________________________________


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

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

Please refer to Note 10 - Derivative Financial Instruments, and to Note 11 - Fair Value Measurements in the ~~2018~~2019 Form 10-K for more information regarding the Company’s derivative instruments.

~~Proved and Unproved~~ Oil and Gas Properties and Other Property and Equipment

Amounts reflected in the total property and equipment, net line item, measured at fair value within the accompanying balance sheets totaled $380.7 million as of March 31, 2020. The Company had 0 assets included in total property and equipment, net, measured at fair value as of December 31, 2019.

Proved oil and gas ~~properties.~~properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses ~~Level 3 inputs and the~~an income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties ~~through the application of~~using a discount ~~rates~~rate, price and ~~price~~cost forecasts, ~~representative of the current operating environment,~~and certain reserve risk-adjustment factors, as selected by the Company’s management.

~~Unproved~~ The Company uses a discount rate that represents a current market-based weighted average cost of capital. The prices for oil and gas ~~properties.~~are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using Oil Price Information Service (“OPIS”) Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties.

Other Property and Equipment. ~~Unproved oil~~Other property and ~~gas property~~equipment costs are evaluated for impairment and reduced to fair value when there is an indication ~~that~~ the carrying costs may not be recoverable. To measure the fair value of ~~unproved properties,~~other property and equipment, the Company uses aan income valuation technique or market approach ~~which takes into account~~depending on the ~~following significant assumptions: remaining lease terms,~~quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future ~~development plans, risk-weighted potential resource recovery, estimated reserve values,~~cash flows associated with the assets, and ~~estimated acreage~~fixed costs necessary to operate and maintain the assets.

As a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities during the three months ended March 31, 2020. The Company used a discount rate of 11 percent in its calculation of the present value of expected future cash flows based on ~~price(s) received for similar, recent acreage transactions by~~ the ~~Company or other market participants.~~ prevailing market-based weighted average cost of capital as of March 31, 2020. NaN proved property impairment expense was recorded during the three months ended March 31, 2019.

The ~~Company recorded~~following table presents impairment of oil and gas properties expense and abandonment and impairment of unproved properties expense ~~of $6.3 million and $25.1 million during~~recorded for the three and nine months ended September 30, 2019, respectively, and $9.1 million and $26.6 million during three and nine months ended September 30, 2018, respectively. These expenses 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.periods presented:



	For the Three Months Ended March 31,
	2020		2019
	(in millions)
Impairment of proved oil and gas properties and related support equipment	$	956.7	$	—
Abandonment and impairment of unproved properties ⁽¹⁾	33.1		6.3
Impairment	$	989.8	$	6.3

____________________________________________

~~Properties held for sale.~~ Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain on divestiture activity line item in the accompanying statements of operations.


⁽¹⁾	These impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of March 31, 2020, and December 31, 2019, are recorded at carrying value.

Please refer to Note 1 - Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the ~~2018~~2019 Form 10-K for more information regarding the Company’s approach in determining the fair value of its properties.

Long-Term Debt

The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of ~~September 30, 2019,~~March 31, 2020, or December 31, ~~2018,~~2019, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion.


	As of September 30, 2019				As of December 31, 2018				As of March 31, 2020				As of December 31, 2019
	Principal Amount		Fair Value		Principal Amount		Fair Value		Principal Amount		Fair Value		Principal Amount		Fair Value
	(in thousands)								(in thousands)
6.125% Senior Notes due 2022	$	476,796	$	459,321	$	476,796	$	452,336	$	436,047	$	190,771	$	476,796	$	481,564
5.0% Senior Notes due 2024	$	500,000	$	448,950	$	500,000	$	439,265	$	500,000	$	148,750	$	500,000	$	479,815
5.625% Senior Notes due 2025	$	500,000	$	431,335	$	500,000	$	436,460	$	500,000	$	145,000	$	500,000	$	475,835
6.75% Senior Notes due 2026	$	500,000	$	440,000	$	500,000	$	448,305	$	500,000	$	150,000	$	500,000	$	494,860
6.625% Senior Notes due 2027	$	500,000	$	432,500	$	500,000	$	442,500	$	500,000	$	149,215	$	500,000	$	493,750
1.50% Senior Convertible Notes due 2021	$	172,500	$	156,706	$	172,500	$	158,614	$	172,500	$	69,576	$	172,500	$	164,430

The carrying value of the Company’s revolving credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.

Note 12 - Leases

~~Effective January 1, 2019, the Company adopted~~ASC Topic 842 ~~which~~- Leases (“Topic 842”), requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of ~~September 30, 2019,~~March 31, 2020, the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases.

As outlined in Topic 842, aan ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement ~~of a ROU asset and corresponding lease liability~~ are certain variable lease payments, ~~such as payments made that vary~~which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on ~~actual usage or performance.~~

The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classificationthe nature and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair valueuse of the underlying ROU asset ~~or assets, upfront costs,~~ and ~~future lease payments that are included or excluded~~in accordance with GAAP requirements.

Please refer to Note 12 - Leases in the ~~initial measurement of~~2019 Form 10-K for more information regarding the ~~ROU asset. Certain~~Company's policy on leases, and assumptions and judgments made byin the ~~Company when evaluating a contract that meets the definition~~initial and subsequent measurement of a lease ~~under Topic 842 include:~~

Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception.

~~Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a~~ ROU ~~asset~~assets and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company.liabilities.

Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease

terms range from less than one year to approximately ~~seven~~six years. The weighted-average lease term remaining for these leases is approximately three years. Certain leases also contain optional extension periods that allow for terms to be extended for up to an

additional 10ten years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement.

~~Subsequent to initial measurement, costs associated~~ Based on expectations for those agreements with ~~the Company’s operating~~early termination options, there are no leases in which material early termination options are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to ~~Note 1 - Summary of Significant Accounting Policies~~ in the Company’s 2018 Form 10-K for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expectedreasonably certain to be ~~made upon commencement of~~exercised by the lease. Excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs.Company.

For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020, and 2019, total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were ~~$107.3~~$72.7 million and ~~$422.4~~$175.3 million, respectively. These totals do not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. Components of the Company’s total lease cost, whether capitalized or expensed, for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020, and 2019, ~~were as follows:~~consisted of the following:



	For the Three Months Ended March 31,
	2020		2019
	(in thousands)
Operating lease cost	$	6,834	$	8,979
Short-term lease cost ⁽¹⁾	43,572		134,917
Variable lease cost ⁽²⁾	22,334		31,408
Total lease cost	$	72,740	$	175,304

____________________________________________

For the Three Months Ended September 30, 2019 For the Nine Months Ended September 30, 2019
(in thousands)
Operating lease cost $ 8,344
$ 28,802
Short-term lease cost ⁽¹⁾
72,874
309,876
Variable lease cost ⁽²⁾
26,090
83,696
Total lease cost ⁽³⁾
$ 107,308
$ 422,374

⁽¹⁾

Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.

⁽²⁾

Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, ~~and~~ completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.


⁽³⁾	~~Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.~~

Other information related to the Company’s leases for the ~~nine~~three months ended ~~September 30,~~March 31, 2020, and 2019, was as follows:


			For the Three Months Ended March 31,
	For the Nine Months Ended September 30, 2019		2020		2019
	(in thousands)		(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	9,029	$	3,046	$	2,952
Investing cash flows from operating leases	$	20,256	$	3,980	$	6,182
Right-of-use assets obtained in exchange for new operating lease liabilities	$	24,014	$	—	$	12,191

Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of ~~September 30, 2019,~~March 31, 2020, were as follows:


	As of September 30, 2019			As of March 31, 2020
	(in thousands)			(in thousands)
2019 (remaining after September 30, 2019)	$	6,871
2020	20,427
2020 (remaining after March 31, 2020)				$	13,997
2021	11,982			12,541
2022	5,712			5,745
2023	3,572			3,602
2024				2,081
Thereafter	3,721			1,640
Total Lease payments	$	52,285		$	39,606
Less: Imputed interest ⁽¹⁾	(5,098		)	(3,816		)
Total	$	47,187		$	35,790


⁽¹⁾	The weighted-average discount rate used to determine the operating lease liability as of ~~September 30, 2019~~March 31, 2020, was ~~6.6~~6.7 percent.

Amounts recorded on the accompanying balance sheets for operating leases as of ~~September 30,~~March 31, 2020, and December 31, 2019, were as follows:


	As of September 30, 2019		As of March 31, 2020		As of December 31, 2019
	(in thousands)		(in thousands)
Other noncurrent assets	$	44,438	$	33,365	$	39,717

Other current liabilities	$	21,804	$	15,780	$	19,189
Other noncurrent liabilities	$	25,384	$	20,010	$	23,137

As of ~~September 30, 2019,~~March 31, 2020, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements ~~at the end~~section of this ~~item~~report for important information about these types of statements.

Overview of the Company

General Overview

~~We are an independent~~Our purpose is to make people’s lives better by responsibly producing energy ~~company engaged~~supplies, contributing to energy security and prosperity, and having a positive impact in the ~~acquisition, exploration, development,~~communities where we live and ~~production~~work. Our long-term vision is to sustainably grow value for all of ~~oil, gas, and NGLs~~our stakeholders. We believe that in ~~onshore North America, with operations currently focused in the state of Texas. Our strategic objective is~~order to accomplish this vision, we must be a premier operator of top tier assets. ~~We seek to maximize the value of~~At present, our ~~assets by applying industry-leading technology and outstanding operational execution. Our~~investment portfolio is ~~comprised of unconventional resource prospects with expanding prospective drilling opportunities, which we believe provides for long-term production and reserves growth. We are~~ focused on ~~generating strong, full-cycle economic returns on our investments~~high quality oil and ~~maintaining a strong balance sheet.~~gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in South Texas.

~~Regional Overview~~Areas of Operations

Our Midland Basin assets are located in the Permian ~~region is~~Basin in West Texas and are comprised of approximately 80,000 net acres ~~in the Midland Basin located in western Texas~~ (“Midland Basin”). ~~Operations in~~In the first quarter of 2020, we focused on continuing to delineate, develop, and expand our Midland Basin ~~are primarily focused on developing~~position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the ~~Lower~~ Spraberry and Wolfcamp A and B intervals on our RockStar acreage in Howard and Martin Counties, Texas, and Lower and Middle Spraberry and Wolfcamp A and B intervals on our Sweetie Peck acreage in Upton and Midland Counties, Texas. We are also actively evaluating and testing additional formations and intervals within our RockStar position, including the Middle Spraberry, Wolfcamp D, and Dean.formations.

Our South Texas ~~& Gulf Coast region is primarily~~assets are comprised of approximately ~~163,000~~158,900 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on developing the Eagle Ford ~~Shale Formation~~shale formation and ~~testing additional intervals and formations, including~~delineating the Austin Chalk ~~Formation.~~formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations includes acreage in oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

~~Third~~First Quarter ~~2019 Highlights~~2020 Overview and Outlook for the Remainder of ~~2019~~2020

The competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic have simultaneously increased supply and decreased demand for oil, gas, and NGLs to historic extremes, and have impacted our entire industry. The implications of these unprecedented events continue to unfold and may have further negative effects to our business such as production curtailment, reduced storage capacity, and reductions to our operating plans. For additional detail, please refer to Risk Factors inPart II, Item 1A of this report and those risk factors previously disclosed in our 2019 Form 10-K.

While we were impacted by these macroeconomic events in the first quarter of 2020, specifically the impacts to the realized prices we receive for our production, and will likely be impacted to a greater degree for the remainder of 2020, we expect to maintain our current ability to sustain strong operational performance and financial stability. We remain focused on maximizing returns and increasing the value of our top tier Midland Basin and South Texas assets. We expect to do this through continued development optimization ~~exploration,~~ and ~~acquisitions.~~delineation. We believe ~~these~~our assets provide significant production growth potential and ~~strong~~ returns that ~~should increase~~are capable of providing internally generated cash flows ~~and~~in low commodity price environments, which support our priorities of improving ~~credit~~leverage metrics and maintaining ~~strong~~ financial flexibility. Our financial risk management program has significantly reduced the impact of substantially lower oil prices in 2020 as a significant amount of our total expected 2020 oil production is covered by derivative contracts at prices greater than or equal to $55.00 per barrel. However, further negative impacts resulting from these events, such as production curtailments and storage capacity constraints, could limit our ability to deliver production and capitalize on the value of our derivative contracts in 2020 and beyond. Given the dynamic nature of the macroeconomic events discussed above, we are unable to reasonably estimate the period of time that these market conditions will exist, the extent of the impact they will have on our business, liquidity, results of operations, financial condition, or the timing of any subsequent recovery.

Sustainability is a key focus of our plans, in terms of positioning ourselves financially to participate in future energy investment opportunities and executing our strategy of being a premier operator with high standards for corporate responsibility. We remain committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference in the communities where we live and work; and transparency in reporting on our progress in these areas. Energy production was deemed an essential business amidst the global COVID-19 pandemic. While the execution of our business operations requires certain individuals to be physically present at well site locations, we implemented processes and protocols where substantially all of our office based people are working remotely in order to restrict physical interactions to mitigate the spread of COVID-19. For individuals who are unable to perform their jobs remotely, we have implemented social distancing measures and continue to communicate and train our employees to maintain a healthy and safe work environment. Since these measures have been implemented, we continue to operate at a very high level without significant disruptions to our ability to operate our business or our control environment.

The information below summarizes our recent operating and financial performance and our expectations for the remainder of 2020, including our liquidity position.

~~Our~~We entered 2020 with a total capital program budgeted to be between $825 million and $850 million. However, given the circumstances discussed above, as of the filing of this report we expect to reduce our 2020 capital program budget by approximately 20 percent for ~~2019, excluding acquisitions, is expected~~the full year 2020. Our financial and operational flexibility allows us to ~~range from $1.00 billion to $1.05 billion.~~continually monitor the economic environment throughout the year and adjust our activity level as warranted. Our 2020 program remains ~~concentrated~~focused on ~~developing~~ our ~~core assets~~most economic oil development projects in ~~the~~both our Midland Basin and South Texas with the majority of our 2019 capital allocated to our Midland Basin program. Drilling and completion activity on our South Texas acreage position was primarily funded by a third party as part of a joint development agreement. All wells subject to this agreement were completed as of September 30, 2019.assets. Please refer to Overview of Liquidity and Capital Resources below for ~~additional~~ discussion onof how we expect to fund our ~~2019~~2020 capital program.

Financial and Operational Results. Average net daily production for the three months ended ~~September 30, 2019,~~March 31, 2020, was ~~134.9~~135.9 MBOE, compared with ~~130.2~~118.7 MBOE for the same period in ~~2018.~~2019. This increase was driven by ~~an 11~~a 32 percent increase in average net daily production volumes from our Midland Basin assets. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased ~~five~~seven percent, 3944 percent, and 4930 percent, respectively, for the three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018.~~2019. As a result of ~~decreased commodity prices,~~increased production, oil, gas, and NGL production revenue ~~decreased 15~~increased four percent to ~~$389.4~~$354.2 million for the three months ended ~~September 30, 2019 from $458.4~~March 31, 2020, compared with $340.5 million for the same period in ~~2018.~~2019. The increase in oil, gas, and NGL production revenue due to increased production was largely offset by decreased pricing. We recorded a net derivative gain of ~~$100.9~~$545.3 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to a net derivative loss of ~~$178.0~~$177.1 million recorded for the same period in ~~2018.~~2019. Included within these derivative amounts is a gain of ~~$24.7~~$73.4 million on derivative contracts that settled during the three months ended ~~September 30, 2019,~~March 31, 2020, and a loss of ~~$40.7~~$5.0 million for the same period in ~~2018. Together, these changes~~2019. Total production costs on a per BOE basis decreased 15 percent to $9.67 per BOE for the three months ended March 31, 2020, from $11.35 per BOE for the same period in 2019. Overall financial and operational activities during the three months ended March 31, 2020, resulted in the following:

net income of $42.2 million, or $0.37 per diluted share, for the three months ended September 30, 2019, compared to a net loss of $135.9 million, or $1.21 per diluted share, for the same period in 2018;

~~net cash provided by operating activities of $203.2 million for the three months ended September 30, 2019, compared with $229.7 million for the same period in 2018;~~


•	net cash provided by operating activities of $218.1 million for the three months ended March 31, 2020, compared with $118.5 million for the same period in 2019. Please refer to Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2020, and 2019 below for additional discussion;

•

net loss of $411.9 million, or $3.64 per diluted share, for the three months ended March 31, 2020, compared with a net loss of $177.6 million, or $1.58 per diluted share, for the same period in 2019. The net loss for the three months ended March 31, 2020, was primarily driven by impairment expense of $989.8 million, partially offset by a net derivative gain of $545.3 million. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and 2019 below for additional discussion regarding the components of net loss for each period presented; and

•

adjusted EBITDAX, a non-GAAP financial measure, for the three months ended ~~September 30, 2019,~~March 31, 2020, was ~~$257.8~~$286.0 million, compared with ~~$256.1~~$186.5 million for the same period in ~~2018.~~2019. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating ~~activities to adjusted EBITDAX.~~activities.

~~Please refer to~~ ~~A Three Month and Nine Month Overview of Selected Production and Financial Information, Including Trends~~, ~~Comparison of Financial Results and Trends Between the Three Months and Nine Months Ended September 30, 2019, and 2018, and~~ ~~Overview of Liquidity and Capital Resources, below for additional discussion on production and production revenues.~~

Operational Activities. The financial results and operational activity discussed throughout this report reflect some of the impacts resulting from the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic. We maintain flexibility to continually monitor the economic environment throughout the year and make related adjustments as warranted.

In our Midland Basin program, we operated ~~six~~five drilling rigs and ~~three~~two completion crews during the ~~third~~first quarter of ~~2019.~~2020. We drilled 25 gross (22 net) wells and completed 19 gross (19 net) wells during the first quarter of 2020, and increased average net daily production volumes year-over-year by 32 percent to 83.4 MBOE per day, 78 percent of which was oil. Costs incurred for oil and gas producing activities in our Midland Basin program during the three months ended March 31, 2020, were $138.7 million, or 83 percent of our total costs incurred for that period. Subsequent to ~~September 30, 2019,~~March 31, 2020, we released one completion crew and ~~we expect~~plan to ~~operate two completion crews for the remainder of 2019. For the full year 2019, we expect~~reduce activity to ~~average six~~four drilling rigs ~~and three completion crews~~ in ~~the Midland Basin and~~July 2020. These plans are subject to ~~allocate approximately 80 percent of our drilling and completion capital~~change in response to ~~our Midland Basin program.~~market conditions. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on delineating and developing the Lower ~~and Middle~~ Spraberry and Wolfcamp A ~~and B~~ shale intervals.

In our South Texas program, we ~~averaged~~operated one drilling rig during the first quarter of 2020. We drilled three gross (three net) wells and completed one gross (one net) well during the first quarter of 2020. Average net daily production for the first quarter of 2020 was 52.5 MBOE, a five percent decrease year-over-year. Costs incurred for oil and gas producing activities in our South Texas program during the three months ended March 31, 2020, were $17.9 million, or 11 percent of our total costs incurred for that period. For the remainder of 2020, we anticipate operating one drilling rig and, ~~one completion crew~~at times during the ~~third quarter of 2019. For the full~~ year, ~~2019, we anticipate averaging one to two drilling rigs and~~ one completion crew in South ~~Texas and expect~~Texas. These plans are subject to ~~allocate approximately 20 percent of our drilling and completion capital~~change in response to ~~this program.~~market conditions. Drilling and completion activities in South Texas continue to focus on developing the Eagle Ford ~~Shale~~shale formation and ~~testing additional intervals and formations, including~~delineating the Austin Chalk Formation. Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to our joint development agreement. All wells subject to this agreement were completed as of September 30, 2019.formation.

The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three ~~and nine~~ months ended ~~September 30, 2019:~~March 31, 2020:


	Midland Basin				South Texas				Total				Midland Basin				South Texas				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Wells drilled but not completed at December 31, 2018	61		55		29		23		90		78
Wells drilled but not completed at December 31, 2019													51		48		21		21		72		69
Wells drilled	31		28		8		7		39		35		25		22		3		3		28		25
Wells completed	(30	)	(27	)	(2	)	(2	)	(32	)	(29	)	(19	)	(19	)	(1	)	(1	)	(20	)	(20	)
Other ⁽¹⁾	—		—		(1	)	—		(1	)	—		—		1		—		—		—		1
Wells drilled but not completed at March 31, 2019	62		56		34		28		96		84
Wells drilled	26		25		7		3		33		28
Wells completed	(36	)	(32	)	(11	)	(11	)	(47	)	(43	)
Wells drilled but not completed at June 30, 2019	52		49		30		20		82		69
Wells drilled	25		22		6		6		31		28
Wells completed	(21	)	(19	)	(17	)	(6	)	(38	)	(25	)
Other ⁽¹⁾	—		—		—		(1	)	—		(1	)
Wells drilled but not completed at September 30, 2019	56		52		19		19		75		71
Wells drilled but not completed at March 31, 2020													57		52		23		23		80		75

____________________________________________


⁽¹⁾	Includes adjustments related to normal business activities, including ~~previously drilled wells that we no longer intend to complete and~~ working interest changes for existing drilled but not completed wells.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled ~~$270.9 million and $861.4~~$167.4 million for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, and were incurred in our Midland Basin and South Texas ~~programs.~~programs as further detailed under Operational Activities above.

Production Results. The table below presents our production by product type for each of our areas of operation for the three months ended ~~September 30, 2019,~~March 31, 2020, and ~~2018:~~2019:


	Midland Basin				South Texas				Total				Midland Basin				South Texas				Total
	Three Months Ended September 30,				Three Months Ended September 30,				Three Months Ended September 30,				Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2019		2018		2019		2018		2020		2019		2020		2019		2020		2019
Production:
Oil (MMBbl)	5.1		4.8		0.3		0.3		5.4		5.0		5.9		4.5		0.4		0.3		6.3		4.8
Gas (Bcf)	9.1		7.1		20.4		20.1		29.5		27.2		9.9		6.9		16.6		17.0		26.5		23.9
NGLs (MMBbl)	—		—		2.1		2.4		2.1		2.4		—		—		1.6		1.9		1.6		1.9
Equivalent (MMBOE)	6.6		6.0		5.8		6.0		12.4		12.0		7.6		5.7		4.8		5.0		12.4		10.7
Avg. daily equivalents (MBOE/d)	71.7		64.8		63.2		65.4		134.9		130.2		83.4		63.3		52.5		55.5		135.9		118.7
Relative percentage	53	%	50	%	47	%	50	%	100	%	100	%	61	%	53	%	39	%	47	%	100	%	100	%

Note: Amounts may not calculate due to rounding.

~~The table below presents our production by product type for each of our areas of operation for the nine months ended September 30, 2019, and 2018:~~

Midland Basin South Texas
Rocky Mountain ⁽¹⁾
Total
Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018 2019 2018 2019 2018
Production:
Oil (MMBbl) 14.8
11.8
0.9
1.0
—
0.9
15.7
13.7
Gas (Bcf) 24.4
18.9
57.3
57.6
—
1.2
81.7
77.7
NGLs (MMBbl) —
—
6.2
5.9
—
—
6.2
6.0
Equivalent (MMBOE) 18.8
15.0
16.7
16.5
—
1.1
35.5
32.6
Avg. daily equivalents (MBOE/d) 69.0
54.9
61.1
60.4
—
4.1
130.1
119.4
Relative percentage 53 % 46 % 47 % 51 % — % 3 % 100 % 100 %

~~Note: Amounts may not calculate due to rounding.~~


⁽¹⁾	~~We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.~~

Please refer to A Three ~~Month and Nine~~ Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and ~~Nine Months Ended September 30,~~ 2019 ~~and 2018~~ below for discussion on production.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average ~~realized~~ price for the respective period, before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, contracted pricing benchmarks, and transportation differentials for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the ~~third and second quarters~~first quarter of ~~2019~~2020 as well as the ~~third quarter~~fourth and first quarters of ~~2018:~~2019:


	For the Three Months Ended									For the Three Months Ended
	September 30, 2019			June 30, 2019			September 30, 2018			March 31, 2020		December 31, 2019			March 31, 2019
Oil (per Bbl):
Average NYMEX contract monthly price	$	56.45		$	59.81		$	69.50		$	46.17	$	56.96		$	54.90
Realized price, before the effect of derivative settlements	$	53.99		$	56.04		$	56.96		$	45.96	$	56.09		$	49.47
Effect of oil derivative settlements	$	(0.41	)	$	(1.97	)	$	(3.32	)	$	8.44	$	(0.87	)	$	(0.28	)
Gas:
Average NYMEX monthly settle price (per MMBtu)	$	2.23		$	2.64		$	2.90		$	1.95	$	2.50		$	3.15
Realized price, before the effect of derivative settlements (per Mcf)	$	2.17		$	2.31		$	3.56		$	1.54	$	2.42		$	2.73
Effect of gas derivative settlements (per Mcf)	$	0.41		$	0.20		$	(0.03	)	$	0.55	$	0.33		$	(0.18	)
NGLs (per Bbl):
Average OPIS price ⁽¹⁾	$	18.89		$	22.23		$	37.97		$	17.02	$	21.96		$	26.28
Realized price, before the effect of derivative settlements	$	15.73		$	16.42		$	30.77		$	13.62	$	17.84		$	19.39
Effect of NGL derivative settlements	$	7.14		$	4.00		$	(9.61	)	$	3.27	$	6.09		$	0.28

____________________________________________


⁽¹⁾	Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

We expect future benchmark prices for oil, gas, and NGLs to remain ~~volatile.~~depressed due to the severe demand declines and global over-supply resulting from the impacts of the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative

strength of the United States dollar compared to other currencies. ~~NGL~~Our realized prices have trended down as an abundance of NGL volumes from increased drilling in liquid-rich areas have over-supplied today’s market. New demand from petrochemical markets and exports have helped to balance the NGL supply.

~~We expect gas prices to remain near current levels~~at local sales points may also be affected by infrastructure capacity in the ~~near term due to the abundance~~area of ~~supply relative to demand. Demand from increased liquefied natural gas (“LNG”) exports~~our operations and ~~gas exports to Mexico are expected to help alleviate oversupply.~~

beyond. Please refer to ~~A Three Month~~First Quarter 2020 Overview and ~~Nine Month Overview~~Outlook for the Remainder of ~~Selected Production and Financial Information, Including Trends~~2020 ~~below~~above for additional discussion ~~on our realized prices for oil, gas, and NGLs.~~of factors impacting pricing.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs ~~(assuming the same composite NGL barrel~~(same product mix as discussed under the table above) as of ~~October 24, 2019,~~April 22, 2020, and ~~September 30, 2019:~~March 31, 2020:


	As of October 24, 2019		As of September 30, 2019		As of April 22, 2020		As of March 31, 2020
NYMEX WTI oil (per Bbl)	$	55.10	$	52.66	$	25.58	$	29.82
NYMEX Henry Hub gas (per MMBtu)	$	2.37	$	2.41	$	2.55	$	2.16
OPIS NGLs (per Bbl)	$	19.70	$	18.89	$	13.27	$	12.30

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of ~~derivatives.~~derivatives, and decisions regarding entering into derivative commodity contracts are overseen by a financial risk management committee consisting of senior executive officers and finance personnel. The amount of our production covered by ~~derivative instruments~~derivatives is driven by the amount of debt on our balance sheet, the ~~magnitude~~level of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity ~~derivative~~ contracts. With our current derivative commodity contracts, we believe we have partially reduced our exposure to volatility in commodity prices and location differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil and gas production.

Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the ~~quarter~~three months ended ~~September 30, 2019,~~March 31, 2020, and the ~~immediately~~ preceding three quarters. ~~A detailed discussion follows.~~


	For the Three Months Ended									For the Three Months Ended
	September 30,		June 30,		March 31,			December 31,		March 31,			December 31,			September 30,		June 30,
	2019		2019		2019			2018		2020			2019			2019		2019
	(in millions)									(in millions)
Production (MMBOE)	12.4		12.4		10.7			11.3		12.4			12.8			12.4		12.4
Oil, gas, and NGL production revenue	$	389.4	$	406.9	$	340.5		$	392.5	$	354.2		$	449.0		$	389.4	$	406.9
Oil, gas, and NGL production expense	$	129.0	$	123.1	$	121.3		$	121.5	$	119.6		$	127.3		$	129.0	$	123.1
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	211.1	$	206.3	$	177.7		$	182.0	$	233.5		$	228.7		$	211.1	$	206.3
Exploration	$	11.6	$	10.9	$	11.3		$	14.3	$	11.3		$	17.7		$	11.6	$	10.9
General and administrative	$	32.6	$	30.9	$	32.1		$	30.4	$	27.4		$	37.2		$	32.6	$	30.9
Net income (loss)	$	42.2	$	50.4	$	(177.6	)	$	309.7	$	(411.9	)	$	(102.1	)	$	42.2	$	50.4

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics



	For the Three Months Ended
	March 31,			December 31,			September 30,			June 30,
	2020			2019			2019			2019
Average net daily production equivalent (MBOE per day)	135.9			138.8			134.9			136.5
Lease operating expense (per BOE)	$	4.75		$	4.67		$	4.73		$	4.16
Transportation costs (per BOE)	$	3.11		$	3.46		$	4.00		$	4.00
Production taxes as a percent of oil, gas, and NGL production revenue	4.2		%	4.2		%	4.1		%	4.0		%
Ad valorem tax expense (per BOE)	$	0.60		$	0.37		$	0.39		$	0.44
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	18.88		$	17.91		$	17.02		$	16.61
General and administrative (per BOE)	$	2.22		$	2.92		$	2.63		$	2.49

____________________________________________

For the Three Months Ended
September 30, June 30, March 31, December 31,
2019 2019 2019 2018
Average net daily production equivalent (MBOE per day) 134.9
136.5
118.7
122.8
Lease operating expense (per BOE) $ 4.73
$ 4.16
$ 5.20
$ 4.98
Transportation costs (per BOE) $ 4.00
$ 4.00
$ 4.08
$ 4.19
Production taxes as a percent of oil, gas, and NGL production revenue 4.1 % 4.0 % 4.1 % 3.4 %
Ad valorem tax expense (per BOE) $ 0.39
$ 0.44
$ 0.76
$ 0.39
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) $ 17.02
$ 16.61
$ 16.63
$ 16.10
General and administrative (per BOE) $ 2.63
$ 2.49
$ 3.00
$ 2.69
Note: Amounts may not calculate due to rounding.

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


	For the Three Months Ended September 30,					Amount Change Between Periods			Percent Change Between Periods			For the Nine Months Ended September 30,								Amount Change Between Periods			Percent Change Between Periods		For the Three Months Ended March 31,						Amount Change Between Periods			Percent Change Between Periods
	2019		2018						Percent Change Between Periods		2019				2018				2020				Percent Change Between Periods			2019					Amount Change Between Periods			Percent Change Between Periods
Net production volumes:⁽¹⁾						Amount Change Between Periods														Amount Change Between Periods
Oil (MMBbl)	5.4		5.0			0.4			7	%		15.7				13.7				2.0			15	%	6.3			4.8			1.5			31	%
Gas (Bcf)	29.5		27.2			2.3			9	%		81.7				77.7				4.0			5	%	26.5			23.9			2.6			11	%
NGLs (MMBbl)	2.1		2.4			(0.3		)	(14	)%		6.2				6.0				0.2			4	%	1.6			1.9			(0.3		)	(14	)%
Equivalent (MMBOE)	12.4		12.0			0.4			4	%		35.5				32.6				2.9			9	%	12.4			10.7			1.7			16	%
Average net daily production:⁽¹⁾
Oil (MBbl per day)	59.0		54.9			4.1			7	%		57.5				50.1				7.4			15	%	69.8			53.7			16.1			30	%
Gas (MMcf per day)	320.6		295.3			25.3			9	%		299.2				284.7				14.5			5	%	291.2			265.5			25.7			10	%
NGLs (MBbl per day)	22.5		26.2			(3.7		)	(14	)%		22.8				21.9				0.9			4	%	17.6			20.8			(3.2		)	(15	)%
Equivalent (MBOE per day)	134.9		130.2			4.6			4	%		130.1				119.4				10.7			9	%	135.9			118.7			17.2			14	%
Oil, gas, and NGL production revenue (in millions): ⁽¹⁾
Oil production revenue	$	292.9	$	287.5		$	5.3		2	%		$	836.1			$	814.7			$	21.3		3	%	$	291.7		$	239.1		$	52.6		22	%
Gas production revenue	64.0		96.8			(32.8		)	(34	)%		194.4				260.0				(65.6		)	(25	)%	40.7			65.1			(24.4		)	(37	)%
NGL production revenue	32.5		74.1			(41.5		)	(56	)%		106.3				169.1				(62.8		)	(37	)%	21.8			36.3			(14.5		)	(40	)%
Total oil, gas, and NGL production revenue	$	389.4	$	458.4		$	(69.0	)	(15	)%		$	1,136.7			$	1,243.8			$	(107.1	)	(9	)%	$	354.2		$	340.5		$	13.8		4	%
Oil, gas, and NGL production expense (in millions): ⁽¹⁾
Lease operating expense	$	58.7	$	52.8		$	5.8		11	%		$	166.0			$	151.9			$	14.1		9	%	$	58.8		$	55.6		$	3.2		6	%
Transportation costs	49.6		50.4			(0.8		)	(2	)%		142.9				144.1				(1.2		)	(1	)%	38.4			43.6			(5.1		)	(12	)%
Production taxes	16.0		19.0			(3.0		)	(16	)%		46.1				53.4				(7.3		)	(14	)%	14.9			14.0			0.8			6	%
Ad valorem tax expense	4.8		5.4			(0.7		)	(12	)%		18.4				16.5				1.9			11	%	7.4			8.1			(0.7		)	(8	)%
Total oil, gas, and NGL production expense	$	129.0	$	127.6		$	1.4		1	%		$	373.4			$	365.9			$	7.5		2	%	$	119.6		$	121.3		$	(1.8	)	(1	)%
Realized price (before the effect of derivative settlements):
Realized price, before the effect of derivative settlements:
Oil (per Bbl)	$	53.99	$	56.96		$	(2.97	)	(5	)%		$	53.31			$	59.60			$	(6.29	)	(11	)%	$	45.96		$	49.47		$	(3.51	)	(7	)%
Gas (per Mcf)	$	2.17	$	3.56		$	(1.39	)	(39	)%		$	2.38			$	3.35			$	(0.97	)	(29	)%	$	1.54		$	2.73		$	(1.19	)	(44	)%
NGLs (per Bbl)	$	15.73	$	30.77		$	(15.04	)	(49	)%		$	17.09			$	28.28			$	(11.19	)	(40	)%	$	13.62		$	19.39		$	(5.77	)	(30	)%
Per BOE	$	31.39	$	38.26		$	(6.87	)	(18	)%		$	32.00			$	38.15			$	(6.15	)	(16	)%	$	28.64		$	31.86		$	(3.22	)	(10	)%
Per BOE data:
Production costs:
Lease operating expense	$	4.73	$	4.41		$	0.32		7	%		$	4.67			$	4.66			$	0.01		—	%	$	4.75		$	5.20		$	(0.45	)	(9	)%
Transportation costs	$	4.00	$	4.20		$	(0.20	)	(5	)%		$	4.02			$	4.42			$	(0.40	)	(9	)%	$	3.11		$	4.08		$	(0.97	)	(24	)%
Production taxes	$	1.29	$	1.58		$	(0.29	)	(18	)%		$	1.30			$	1.64			$	(0.34	)	(21	)%	$	1.20		$	1.31		$	(0.11	)	(8	)%
Ad valorem tax expense	$	0.39	$	0.45		$	(0.06	)	(13	)%		$	0.52			$	0.51			$	0.01		2	%	$	0.60		$	0.76		$	(0.16	)	(21	)%
Total production costs ⁽¹⁾																									$	9.67		$	11.35		$	(1.68	)	(15	)%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	17.02	$	16.78		$	0.24		1	%		$	16.76			$	14.82			$	1.94		13	%	$	18.88		$	16.63		$	2.25		14	%
General and administrative	$	2.63	$	2.46		$	0.17		7	%		$	2.69			$	2.64			$	0.05		2	%	$	2.22		$	3.00		$	(0.78	)	(26	)%
Derivative settlement gain (loss) ⁽²⁾	$	1.99	$	(3.40	)	$	5.39		159	%		$	0.67			$	(3.13	)		$	3.80		121	%	$	5.94		$	(0.47	)	$	6.41		1,364	%
Earnings per share information:
Basic weighted-average common shares outstanding (in thousands)	112,804		112,107			697			1	%		112,441				111,836				605			1	%	113,009			112,252			757			1	%
Diluted weighted-average common shares outstanding (in thousands)	113,334		112,107			1,227			1	%		112,441				113,600				(1,159		)	(1	)%	113,009			112,252			757			1	%
Basic net income (loss) per common share	$	0.37	$	(1.21	)	$	1.58		131	%		$	(0.76	)		$	1.78			$	(2.54	)	(143	)%
Diluted net income (loss) per common share	$	0.37	$	(1.21	)	$	1.58		131	%		$	(0.76	)		$	1.75			$	(2.51	)	(143	)%
Basic net loss per common share																									$	(3.64	)	$	(1.58	)	$	(2.06	)	130	%
Diluted net loss per common share																									$	(3.64	)	$	(1.58	)	$	(2.06	)	130	%

______________________________________


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


⁽²⁾	Derivative settlements for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020, and 2019, ~~and 2018,~~ are included within the net derivative (gain) loss line item in the accompanying statements of operations.

Average ~~net~~daily equivalent ~~daily~~ production for the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, increased ~~four~~14 percent ~~and nine percent, respectively,~~ compared with the same ~~periods~~period in ~~2018. These results were primarily~~2019. This increase was driven by ~~the performance of~~a 32 percent increase in average daily equivalent production volumes from our Midland Basin assets ~~which had increases in production volumes of 11 percent and 26 percent~~ for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018. Production~~2019. Average daily equivalent production volumes from our South Texas assets decreased ~~three percent and increased one~~five percent for the three ~~and nine~~ months ended September 30, 2019, respectively. We divested our remaining producing assets in the Rocky Mountain region in the first half of 2018. On a retained asset basis, production volumes increased 13 percent for the nine months ended September 30, 2019,March 31, 2020, compared with the same period in ~~2018.~~2019. For the full year ~~2019,~~2020, we expect total production ~~as well as oil production as a percentage of our total product mix,~~volumes to ~~increase~~decline compared with ~~2018, primarily as a result of actual and anticipated production increases in our Midland Basin program. Currently, we expect production volumes from South Texas to remain flat year over year.~~2019.

~~Below is a discussion of certain financial results, some of which are presented on a per BOE basis.~~ We present ~~this~~certain information on a per BOE basis ~~because we believe it is an effective way~~in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our realized price before the effect of derivative settlements on a per BOE basis decreased ~~18 percent and 16~~10 percent for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018. These decreases were~~2019, primarily driven by lower benchmark commodity prices for oil, gas, and NGLs. ~~In addition~~This decrease was partially offset by an increase in oil production as a percentage of total production from 45 percent for the three months ended March 31, 2019, to ~~lower commodity prices, regional~~51 percent for the three months ended March 31, 2020. Regional pricing differentials in the Midland Basin ~~caused by tight takeaway capacity further affected realized prices. In the first half of 2019, certain third-party midstream force majeure events~~ negatively affected ~~the price we received for~~ our ~~Midland Basin gas production. Regional differentials for gas~~realized prices in ~~the Midland Basin~~2019 and are expected to continue to negatively affect our realized prices ~~into 2020, when additional expected take-away capacity is anticipated to come on-line.~~in 2020. For the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, we recognized ~~gains~~a gain of ~~$1.99 and $0.67~~$5.94 per BOE, ~~respectively,~~ on the settlement of our derivative contracts, compared to a recognized ~~losses~~loss of ~~$3.40 and $3.13~~$0.47 per BOE for the three ~~and nine~~ months ended ~~September 30, 2018, respectively.~~March 31, 2019.

Lease operating expense (“LOE”) on a per BOE basis ~~increased seven~~decreased nine percent for the three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018.~~2019. This ~~increase~~decrease was primarily driven by increased ~~LOE~~production and ~~workover expense on~~continued efforts to reduce costs as part of our ~~South Texas assets. For the nine months ended September 30, 2019, LOE on a per BOE basis was flat compared with the same period in 2018.~~operating plan. For the full year 2020, we expect LOE on a per BOE basis to be ~~flat in 2019~~higher compared with ~~2018. We may experience~~2019 as our product mix continues to shift towards more oil production. While we will continue our efforts to reduce costs during 2020, we anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and ~~changes in~~ industry activity, ~~and the effects such changes could have on~~all of which impacts service provider costs.

Transportation costs on a per BOE basis decreased ~~five percent and nine~~24 percent for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018. These decreases were~~2019. This decrease was driven ~~primarily~~ by ana five percent reduction in average daily equivalent production volumes from our South Texas assets for the three months ended March 31, 2020, compared with the same period in 2019, and a 32 percent increase in ~~the percentage of~~average daily equivalent production volumes generated from our Midland Basin assets, as production from these assets is typically sold at or near the wellhead and incurs minimal transportation costs. We expect total transportation costs to fluctuate relative to changes in production from our South Texas assets, which incur the majority of our transportation costs. On a per BOE basis, we expect transportation costs to decrease in ~~2019,~~2020, compared with ~~2018,~~2019, as production from our Midland Basin assets continues to become a larger portion of our total production.

Production taxes on a per BOE basis decreased ~~18 percent and 21~~eight percent for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018. These decreases were~~2019. This decrease was primarily driven by ~~the 18 percent and 16 percent decreases~~a decrease in realized ~~price on~~prices and an increase in oil production volumes as a ~~per BOE basis before the effects~~percent of ~~derivative settlements for the three and nine months ended September 30, 2019, respectively, compared with the same periods in 2018.~~total production volumes. Our overall production tax rate for each of the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020, and 2019 was 4.2 percent and 4.1 percent, ~~compared to 4.1 percent and 4.3 percent for the three and nine months ended September 30, 2018,~~ respectively. ~~The decrease in~~We expect our overall production tax rate ~~for the nine months ended September 30, 2018 was primarily the result of divesting our producing assets~~to remain consistent in ~~the Rocky Mountain region, which were subject to higher tax rates than our properties in Texas.~~2020, compared with 2019. We generally expect production tax expense to trend with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax we recognize.

Ad valorem tax expense on a per BOE basis decreased 1321 percent for the three months ended ~~September 30, 2019, compared to the same period in 2018. For the nine months ended September 30, 2019, ad valorem tax expense per BOE was relatively flat~~March 31, 2020, compared with the same period in ~~2018 as the expected increases on an absolute basis were consistent with higher~~2019, resulting from changes in our asset and production ~~volumes.~~base. We ~~expect our full-year 2019~~anticipate volatility in ad valorem tax expense ~~to remain consistent with 2018~~ on a per BOE and absolute basis as ~~increases on an absolute basis continue to trend~~a result of continuing changes in ~~line with higher production volumes.~~the valuation of our producing properties.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased ~~one percent and 13~~14 percent for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018. These increases were~~2019. This increase was driven by our focus on developing oil producing assets in the Midland Basin, which have higher depletion rates than our primarily gas and NGL producing assets in South Texas. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. ~~In general, we~~We expect DD&A expense on a per BOE basis ~~in 2019~~ to ~~increase~~decrease for the remainder of 2020 compared with ~~2018 as production from~~ the ~~Midland Basin continues to increase~~three months ended March 31, 2020, and compared with the year ended December 31, 2019, as a ~~percentage~~result of a reduction in the depletable cost basis of our ~~total production.~~

proved oil and gas properties resulting from proved property impairments during the three months ended March 31, 2020.

General and administrative (“G&A”) expense on a per BOE basis ~~increased seven percent and two~~decreased 26 percent for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018. These increases are~~2019. This decrease is primarily due to ~~less employee compensation being reclassified to exploration expense as more employee time is being allocated to development activities. As we expect a continued high focus of capital allocation to~~increased production and the ~~Midland Basin, we reorganized certain functions during~~reorganization in the fourth quarter of 2019 ~~to eliminate~~of certain functions that eliminated duplicative regional ~~operation~~operational functions and ~~reduce~~reduced overhead costs, which we expect will result in reduced G&A expense in future years. As a result, we expect to incur total charges related to this reorganization ranging from $7.0 million to $8.5 million, including a range of $3.0 million to $5.0 million to be incurred incosts. For the ~~fourth quarter of 2019. Therefore,~~full year 2020, we expect G&A expense ~~for the full-year 2019~~ to ~~increase~~decrease compared with ~~2018.~~2019.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and ~~Nine Months Ended September 30,~~ 2019 ~~and 2018~~ below for additional discussion on operating expenses.

Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for discussion of our basic and diluted net ~~income (loss)~~loss per common share calculations.

Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2020, and ~~Nine Months Ended September 30,~~ 2019 ~~and 2018~~

Net equivalent production, production revenue, and production expense

The following table presents the regional changes in our net equivalent production, production revenue, and production expense between the three months ended ~~September 30, 2019,~~March 31, 2020, and ~~2018:~~2019:


	Net Equivalent Production Increase (Decrease)		Production Revenue Decrease			Production Expense Increase (Decrease)			Net Equivalent Production Increase (Decrease)		Production Revenue Increase (Decrease)			Production Expense Increase (Decrease)
	(MBOE per day)		(in millions)			(in millions)			(MBOE per day)		(in millions)			(in millions)
Midland Basin	6.9		$	(15.7	)	$	1.8		20.1		$	46.7		$	7.5
South Texas	(2.3	)	(53.2		)	(0.4		)	(3.0	)	(32.9		)	(9.3		)
Total	4.6		$	(69.0	)	$	1.4		17.2		$	13.8		$	(1.8	)

__________________________________________

Note: Amounts may not calculate due to rounding.

~~The following table presents the regional changes~~We experienced a 14 percent increase in ~~our~~ net equivalent daily production ~~production revenue, and production expense between the nine months ended September 30, 2019, and 2018:~~

Net Equivalent Production
Increase (Decrease) Production Revenue
Increase (Decrease) Production Expense
Increase (Decrease)
(MBOE per day) (in millions) (in millions)
Midland Basin 14.1
$ 39.7
$ 24.3
South Texas 0.7
(89.5 ) 6.5
Rocky Mountain ⁽¹⁾
(4.1 ) (57.2 ) (23.3 )
Total 10.7
$ (107.1 ) $ 7.5

~~__________________________________________~~

~~Note: Amounts may not calculate due to rounding.~~


⁽¹⁾	~~We divested our remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.~~

~~As previously discussed, production on a net equivalent basis increased four percent and nine percent~~ for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018,~~2019, primarily as a result of increased production ~~primarily~~ from our Midland Basin assets. ~~Oil,~~Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased seven percent, 44 percent, and 30 percent, respectively, for the three months ended March 31, 2020, compared with the same period in 2019. As the increase in production slightly offset lower pricing, oil, gas, and NGL production ~~revenues decreased 15~~revenue increased four percent for the three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018, primarily as a result of decreases in commodity prices. Oil, gas, and NGL~~2019.

Total production ~~revenues decreased nine percent~~expense for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018, as a result of weaker commodity pricing~~2019, decreased one percent. Decreases in transportation costs and ~~the divestiture~~ad valorem tax expense were offset by increases in the first half of 2018 of our remaining producing assets in the Rocky Mountain region. On a retained asset basis, production volumes increased 13 percent for the nine months ended September 30, 2019, compared with the same period in 2018. Total production expense for the three and nine months ended September 30, 2019, compared with the same periods in 2018, was relatively flat as increased lease operating ~~expense was offset by decreased~~expenses and production taxes and transportation costs. Production expense on a per BOE basis decreased two percent and six percent for the three and nine months ended September 30, 2019, respectively, compared with the same periods in 2018, primarily due to increased production volumes, decreased transportation costs on a per BOE basis, and decreased production taxes driven by lower oil, gas, and NGL production revenues.taxes. Please refer to A Three ~~Month and Nine~~ Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including trends on a per BOE basis.

~~Net gain on divestiture activity~~

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in millions)
Net gain on divestiture activity $ —
$ 0.8
$ 0.3
$ 425.7

The $425.7 million net gain on divestiture activity recorded for the nine months ended September 30, 2018, was primarily the result of an estimated net gain of $410.6 million recorded for the PRB Divestiture, which closed in the first quarter of 2018. Please refer to ~~Note 3 - Divestitures, Assets Held for Sale, and Acquisitions~~ ~~in Part I, Item 1 of this report for additional discussion.~~

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

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 211.1
$ 201.1
$ 595.2
$ 483.3



	For the Three Months Ended March 31,
	2020		2019
	(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	233.5	$	177.7

DD&A expense increased ~~five percent and 23~~31 percent for the three ~~and nine~~ months ended ~~September 30, 2019, respectively,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018. The increases~~2019. This increase is directly ~~relate~~related to the 1132 percent ~~and 26 percent increases~~increase in average daily equivalent production volumes from our Midland Basin assets ~~for the three and nine months ended September 30, 2019, respectively,~~ as these assets have higher depletion rates than our assets in South Texas.

Exploration


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,				For the Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
	(in millions)								(in millions)
Geological and geophysical expenses	$	1.1	$	0.6	$	2.0	$	4.5	$	1.2	$	0.4
Overhead and other expenses	10.5		12.5		31.9		36.3		10.1		10.9
Total exploration	$	11.6	$	13.1	$	33.9	$	40.8
Total									$	11.3	$	11.3

Exploration expense ~~decreased 11 percent and 17 percent~~remained flat for the three ~~and nine~~ months ended September 30, 2019, respectively, compared with the same periods in 2018. The decreases were primarily driven by a reduction in the amount of employee compensation reclassified to exploration expense as more employee time is being allocated to development activities, which is recognized as G&A expense. Additionally, spending on geological and geophysical activities decreased for the nine months ended September 30, 2019,March 31, 2020, compared with the same period in ~~2018. In 2019,~~2019. For the full year 2020, we expect ~~total~~ exploration expense to ~~be slightly lower~~decrease compared with ~~2018;~~2019 as a result of lower overhead; however, ~~our expectations could change depending on~~exploration expense is impacted by actual geological and geophysical studies ~~performed~~we perform and the potential for exploratory dry hole expense.

Impairment ~~of proved properties~~ ~~and~~ ~~Abandonment and impairment of unproved properties~~

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in millions)
Abandonment and impairment of unproved properties $ 6.3
$ 9.1
$ 25.1
$ 26.6



	For the Three Months Ended March 31,
	2020		2019
	(in millions)
Impairment of proved oil and gas properties and related support equipment	$	956.7	$	—
Abandonment and impairment of unproved properties	33.1		6.3
Total	$	989.8	$	6.3

As a result of the decrease in commodity price forecasts at the end of the first quarter 2020, specifically decreases in oil and NGL prices, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities during the three months ended March 31, 2020. There were no proved oil and gas property impairments recorded for the ~~three and nine months ended September 30, 2019 and 2018.~~same period in 2019. Unproved property ~~abandonment~~abandonments and ~~impairment expense~~impairments recorded for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020, and 2019 ~~and 2018~~ related to actual and anticipated lease expirations, as well as actual and anticipated losses onof acreage due to title defects, changes in development plans, and other inherent acreage risks.

We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.

~~Future~~Reserve estimates and related impairments of proved and unproved properties are difficult to ~~predict; however, based on our commodity~~predict in a volatile price ~~assumptions as of October 24, 2019,~~environment. Due to the supply impacts associated with the competition between Russia and Saudi Arabia for crude oil market share and demand impacts associated with the global COVID-19 pandemic, we ~~do not expect any material~~may experience additional proved and unproved property impairments in the ~~fourth quarter~~future if commodity prices for the products we produce continue to decline. Given these current uncertainties in commodity prices and the associated impacts they may have on service provider costs, we cannot predict with any reasonable certainty the likelihood or magnitude of ~~2019 resulting from commodity price impacts.~~further property impairments beyond those recorded during the period ended March 31, 2020.

Please refer to Note 11 - Fair Value Measurementsin Part I, Item 1 of this report for additional discussion of impairment expense.

General and administrative

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in millions)
General and administrative $ 32.6
$ 29.5
$ 95.6
$ 86.1



	For the Three Months Ended March 31,
	2020		2019
	(in millions)
General and administrative	$	27.4	$	32.1

G&A expense ~~increased 11~~decreased 14 percent for ~~each of~~ the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, compared with the same ~~periods~~period in ~~2018.~~2019. Please refer to the section A Three ~~Month and Nine~~ Month Overview of Selected Production and Financial Information, Including Trends above for ~~further~~additional discussion of G&A expense in total and on a per BOE basis.

Net derivative (gain) loss

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in millions)
Net derivative (gain) loss $ (100.9 ) $ 178.0
$ (3.5 ) $ 249.3



	For the Three Months Ended March 31,
	2020			2019
	(in millions)
Net derivative (gain) loss	$	(545.3	)	$	177.1

We recognized a $545.3 million derivative gain for the three months ended March 31, 2020. The gain was primarily driven by a $471.9 million upward mark-to-market adjustment due to weakening oil prices during the first three months of 2020. There was a $73.4 million gain on derivative contracts that settled during the three months ended March 31, 2020.

We recognized a $177.1 million derivative loss infor the ~~first quarter of 2019, and derivative gains of $79.7 million and $100.9 million in the second and third quarters of 2019, respectively. The~~three months ended March 31, 2019. This loss ~~in the first quarter of 2019~~ was primarily driven by a $172.1 million downward mark-to-market adjustment on derivative contracts settling subsequent to March 31, 2019, due to strengthening oil prices during the first three months of ~~the year. The derivative gains recognized in the second and third quarters were primarily driven by increases in the fair value~~2019. There was an additional loss of ~~derivative contracts settling subsequent to June 30, 2019, and September 30, 2019, of $75.6~~$5.0 million ~~and $76.2 million, respectively, as a result of weakening commodity prices during these periods. In addition, there was a $23.8 million gain~~ on derivative contracts that settled during the ~~nine months ended September 30, 2019.~~

~~We recognized a $178.0 million derivative loss for the~~ three months ended September 30, 2018, due in part to a $186.0 million decrease in the fair value of contracts settling subsequent to September 30, 2018. Additionally, we recognized an $8.0 million gain on contracts that settled during the third quarter of 2018, which had a fair value of $48.7 million at June 30, 2018, and settled for a loss of $40.7 million. We recognized a $7.6 million loss on first and second quarter 2018 contract settlements and recorded a $63.7 million decrease to the fair value of remaining contracts as of June 30, 2018, resulting in a year-to-date net derivative loss of $249.3 million for the nine months ended September 30, 2018.March 31, 2019.

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

Interest expense

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in millions)
Interest expense $ 40.6
$ 38.1
$ 118.2
$ 122.9



	For the Three Months Ended March 31,
	2020		2019
	(in millions)
Interest expense	$	41.5	$	38.0

Interest expense increased ~~six~~nine percent for the three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018~~2019 as a result of increased interest expense associated with borrowings against our revolving credit facility in ~~2019. Our credit facility remained undrawn throughout 2018.~~

Interest expense decreased four percent for the nine months ended September 30, 2019, compared with the same period in 2018. This decrease was driven primarily by the redemption of our 2021 Senior Notes in the third quarter of 2018, which reduced interest expense related to debt during the nine months ended September 30, 2019 by $12.1 million compared with the same period in 2018. This decrease was partially offset by increased interest expense associated with borrowings against our credit facility in 2019 whereas no borrowings were made against our credit facility in 2018.2020. We expect interest expense related to our Senior Notes to remain relatively flat for the remainder of ~~2019~~2020 compared with ~~2018;~~2019; however, total interest expense will vary based on the timing and amount of borrowings against our revolving credit ~~facility throughout the remainder~~facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of ~~2019.~~this report and Overview of Liquidity and Capital Resources below for additional discussion.

~~Loss~~Gain on extinguishment of debt

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2019 2018 2019 2018
(in millions)
Loss on extinguishment of debt $ —
$ 26.7
$ —
$ 26.7



	For the Three Months Ended March 31,
	2020		2019
	(in millions)
Gain on extinguishment of debt	$	12.2	$	—

~~For the three and nine months ended September 30, 2018, we~~We recorded a ~~$26.7~~$12.2 million net ~~loss~~gain on the early extinguishment of ~~our 2021 Senior Notes, 2023 Senior Notes, and~~ a portion of our 2022 Senior Notes during the three months ended March 31, 2020, which included ~~$20.4~~discounts realized upon repurchase of $12.4 million ~~associated with the premiums paid upon redemption and repurchase, and $6.3 million related to the acceleration~~partially offset by approximately $235,000 of accelerated unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional ~~information.~~

~~Please refer to~~ ~~Note 5 - Long-Term Debt~~ ~~in Part I, Item I of this report and~~ ~~Overview of Liquidity and Capital Resourcesbelow for additional information.~~discussion.

Income tax ~~(expense)~~ benefit


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(in millions, except tax rate)												(in millions, except tax rate)
Income tax (expense) benefit	$	(16.1	)	$	36.7		$	16.3		$	(61.3	)
Income tax benefit													$	99.0		$	46.0
Effective tax rate	27.6		%	21.3		%	16.1		%	23.6		%	19.4		%	20.6		%

The ~~increase~~decrease in the effective tax rate for the three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018,~~2019, was primarily due to recording a valuation allowance for deferred tax assets we determined were not likely to be utilized after we recorded proved property impairments during the ~~differing~~first quarter of 2020. The tax rates reflect proportional effects of ~~permanent items on~~changes to forecast income ~~before income taxes for the three months ended September 30, 2019, compared~~or loss and forecast changes to ~~their impact on the loss before income taxes for the same period in 2018.~~

The decrease in the effective tax rate for the nine months ended September 30, 2019, compared with the same period in 2018, was primarily due to the differing effects of permanent items on the loss before income taxes for the nine months ended September 30, 2019, compared to their impact on income before income taxes for the same period in 2018.

~~Discrete expenses related to~~valuation allowances, excess tax deficiencies from stock-based compensation awards, and limits toon expensing of certain covered individual’s compensation, and other permanent expense items reduced the tax benefit rate for the nine months ended September 30, 2019, and the three months ended September 30, 2018. These same items increased the tax expense rate for the three months ended September 30, 2019, and the nine months ended September 30, 2018. The reduction in the tax expense rate also reflects a cumulative effect in 2018 from divestitures, and the impact of a correlative change to our state apportionment rate.

compensation. Please refer to~~Overview of Liquidity and Capital Resources~~ ~~below as well as~~ Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

Sources of Cash

We currently expect our ~~2019~~2020 capital program to be funded by cash flows from operations with any remaining cash ~~that was on hand as of December 31, 2018, and~~needs being funded by borrowings under our revolving credit facility. During the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, we generated

~~$581.6~~ $218.1 million of cash flows from operating activities. As of ~~September 30, 2019,~~filing on April 29, 2020, the remaining available borrowing capacity under our Credit Agreement provided ~~$1.1~~$1.0 billion in ~~liquidity.~~liquidity; however, our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities. Please refer to Credit Agreement below for additional discussion.

Although we expect cash flows from these sources to be sufficient to fund our expected ~~2019~~2020 capital program, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. Further, we may enter into additional carrying cost funding and sharing arrangements with third parties for certain exploration or development programs. Our borrowing base could be reduced as a result of lower commodity prices, divestitures of properties with proved reserves, or the issuance of additional debt securities. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly-issued securities may have rights, preferences, or privileges senior to those of existing stockholders. ~~Future downgrades in our credit ratings could make it more difficult~~Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or ~~expensive for us to borrow additional funds.~~development programs. All of our

sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, and fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry.

As a result of the current macroeconomic environment, our credit ratings were recently downgraded by three major rating agencies. These downgrades and any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Current or future macroeconomic events may negatively impact our ability to capitalize on these contracts. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts.

The enactment of the Tax Cuts and Jobs Act (the “2017 Tax Act”) reduced our highest marginal corporate tax rate for 2018 and future years from 35 percent to 21 percent, however future deductibility of interest expense may be limited. In general, the enactment of the 2017 Tax Act has had a positive impact on operating cash flows, and we believe it will positively impact future operating cash flows.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion and is scheduled to mature on September 28, 2023. The maturity date could, however, occur earlier on August 16, 2022, if we have not completed certain repurchase, redemption, or refinancing activities associated with our 2022 Senior Notes, as outlined in the Credit Agreement.billion. The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each as determined by our lender group. On April 29, 2020, we entered into the Third Amendment with our lenders, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were both reduced to $1.1 billion due to a decrease in the value of proved reserves as a result of decreased commodity pricing. The next scheduled borrowing base redetermination date is ~~April~~October 1, 2020.

~~Our daily weighted-average~~ 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, ~~facility debt balance was approximately $170.9 million~~ and $97.5 million for the three and nine months ended September 30, 2019. Our credit facility remained undrawn throughout 2018. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, and our capital expenditures all impact the amount we borrowavailable borrowing capacity under our ~~credit facility.~~Credit Agreement as of filing on April 29, 2020, March 31, 2020, and December 31, 2019.

We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as ~~defined by~~set forth in the Credit Agreement. The financial covenants under the Credit Agreement require that our (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which will use annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ended December 31, 2018 through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to ~~1.00;~~1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. We were in compliance with all financial and non-financial covenants as of ~~September 30, 2019,~~March 31, 2020, and through the filing of this report. Please refer to the caption Non-GAAP Financial Measures below for our definition of adjusted EBITDAX and reconciliations of net ~~income (loss)~~loss and net cash provided by operating activities to adjusted EBITDAX.

Our daily weighted-average revolving credit facility debt balance was approximately $104.1 million and $12.1 million for the three months ended March 31, 2020, and 2019, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Our Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. We currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business. Please refer to Note 1 - Summary of Significant Accounting Policiesfor discussion of FASB ASU 2020-04 which provides guidance related to reference rate reform.

Weighted-Average Interest and Weighted-Average Borrowing Rates

Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and the non-cash amortization of the discount related to the Senior Convertible Notes. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, and ~~2018:~~2019:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,				For the Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
Weighted-average interest rate	6.3	%	6.4	%	6.4	%	6.4	%	6.5	%	6.5	%
Weighted-average borrowing rate	5.6	%	5.7	%	5.7	%	5.8	%	5.7	%	5.8	%

Our weighted-average interest rates and weighted average borrowing rates ~~for the three and nine months ended September 30, 2019, and 2018, were~~are impacted by the timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit ~~facility under the Credit Agreement, and~~facility. Additionally, our weighted-average interest rates are impacted by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect amounts associated with the repurchase of a portion of our 2022 Senior Notes, such as the ~~premium paid upon repurchase,~~discount realized or the acceleration of unamortized deferred financing costs expensed upon repurchase. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Uses of Cash

We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, we spent ~~$788.6~~$139.3 million on capital expenditures. This amount differs from the costs incurred amount of ~~$861.4~~$167.4 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.

The amount and allocation of our future capital expenditures will depend upon a number of factors, including the number and size of acquisitions, our cash flows from operating, investing, and financing activities, and our ability to execute our development program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes inare necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. We entered 2020 with a total capital program budgeted to be between $825 million and $850 million. However, given the macroeconomic events discussed throughout this report, we currently expect to reduce our 2020 capital program budget by approximately 20 percent for the full year 2020. Given the dynamic nature of the macroeconomic events discussed throughout this report, we are unable to reasonably estimate the period of time that these market conditions will exist, the extent of the impact they will have on our business, liquidity, results of operations, financial condition, or the timing of any subsequent recovery. We will continue to monitor the economic environment throughout the year and adjust our activity level as warranted.

We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a combination of both. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. ~~Repurchases or exchanges are reviewed as part of the allocation of our capital.~~ During the ~~third~~first quarter of ~~2018, the Company redeemed its 2021 Senior Notes, repurchased or redeemed all of its 2023 Senior Notes,~~2020, we repurchased a ~~portion~~total of ~~its~~$40.7 million of our 2022 Senior Notes ~~and issued its 2027 Senior Notes. We have not conducted similar~~in open market transactions at a discount, resulting in a gain on extinguishment of debt ~~transactions through September 30, 2019, or through~~of $12.2 million. Additionally, we decreased the ~~filing~~outstanding balance of ~~this report.~~our revolving credit facility by $50.5 million during the first quarter of 2020. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. As part of our strategy for 2020, we expect to continue to focus on improving our debt metrics, which could include further reducing the amount of our outstanding debt.

As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes, the indenture governing our Senior Convertible Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of ~~2019.~~2020.

Analysis of Cash Flow Changes Between the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020, and 2019 ~~and 2018~~

The following tables present changes in cash flows between the ~~nine~~three months ended ~~September 30,~~March 31, 2020, and 2019, ~~and 2018,~~ for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying unaudited condensed consolidated statements of cash flows in Part I, Item 1 of this report.

Operating activities

For the Nine Months Ended
September 30, Amount Change Between Periods
2019 2018
(in millions)
Net cash provided by operating activities $ 581.6
$ 541.2
$ 40.4



	For the Three Months Ended March 31,				Amount Change Between Periods
	2020		2019		Amount Change Between Periods
	(in millions)
Net cash provided by operating activities	$	218.1	$	118.5	$	99.6

~~Derivative cash settlements increased $125.9 million for the nine months ended September 30, 2019, compared with the same period in 2018. This increase was partially offset by decreased cash~~

Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes ~~of $80.7~~increased $105.7 million and cash received from settled derivative trades increased $19.5 million for the three months ended March 31, 2020, compared with the same period in 2019. These increases were partially offset by increased cash paid for LOE and ad valorem taxes of ~~$22.2~~$16.3 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018.~~2019. Cash paid for interest ~~decreased $11.3~~increased $7.5 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in 2018, due to the redemption and repurchase of certain senior notes in the third quarter of 2018, partially offset by increased interest paid on the 2027 Senior Notes and interest paid on credit facility borrowings during the nine months ended September 30, 2019. Net cash provided by operating activities is also affected 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
2019 2018
(in millions)
Net cash used in investing activities $ (778.7 ) $ (314.0 ) $ (464.7 )



	For the Three Months Ended March 31,						Amount Change Between Periods
	2020			2019			Amount Change Between Periods
	(in millions)
Net cash used in investing activities	$	(139.3	)	$	(242.9	)	$	103.6

~~The increase in~~Net cash used in investing activities decreased for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018, is~~2019, primarily due to ~~a decrease in proceeds from the sale of oil and gas properties of $730.7 million. This decrease is partially offset by a decrease in~~reduced capital expenditures ~~and a decrease in cash paid to acquire proved and unproved oil and gas properties~~ of ~~$243.9 million and $22.0 million, respectively.~~$110.0 million.

Financing activities

For the Nine Months Ended
September 30, Amount Change Between Periods
2019 2018
(in millions)
Net cash provided by (used in) financing activities $ 122.7
$ (364.4 ) $ 487.1



	For the Three Months Ended March 31,					Amount Change Between Periods
	2020			2019		Amount Change Between Periods
	(in millions)
Net cash provided by (used in) financing activities	$	(78.8	)	$	46.5	$	(125.3	)

Net cash ~~provided by (used in)~~used in financing activities increased ~~$487.1~~$125.3 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared with the same period in ~~2018.~~2019. During the ~~nine~~three months ended ~~September 30, 2019, net borrowings under~~March 31, 2020, we repaid $50.5 million of our outstanding revolving credit facility balance, compared with increased ~~$129.0 million. Our credit facility remained undrawn throughout 2018.~~borrowings of $46.5 million for the same period in 2019. During the ~~nine months ended September 30, 2018,~~first quarter of 2020, we ~~redeemed $344.6~~repurchased a total of $40.7 million in aggregate principal ~~outstanding on our 2021 Senior Notes, and repurchased $395.0 million principal outstanding of our 2023 Senior Notes and $85.0 million principal outstanding~~amount of our 2022 Senior ~~Notes. As a result, premiums totaling $20.4 million were~~Notes in open market transactions for cash paid, ~~in connection with these redemptions and repurchases. Additionally, we issued our 2027 Senior Notes for net proceeds~~excluding interest, of ~~$492.1~~$28.3 million. There were no ~~such~~ debt transactions related to our Senior Notes during the ~~nine months ended September 30,~~same period in 2019. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of ~~September 30, 2019,~~March 31, 2020, we had a ~~$129.0~~$72.0 million balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair ~~market~~ value but will not impact results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair ~~market~~ value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes or fixed-rate Senior Convertible Notes but can impact their fair ~~market~~ values. As of ~~September 30, 2019,~~March 31, 2020, our outstanding principal amount of fixed-rate debt totaled $2.6 billion and our floating-rate debt outstanding totaled ~~$129.0~~$72.0 million. Please refer to Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes and Senior Convertible Notes.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to ~~wide~~unpredictable fluctuations ~~in response to~~resulting from a variety of factors, including changes in supply and demand and ~~other factors that~~the macroeconomic environment, all of which are typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several ~~years,~~months and ~~these markets~~years. In recent weeks, oil and NGL prices have weakened to historic lows as a result of the impacts of the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic. These prices will likely continue to be volatile in the future. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our production for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately ~~$83.6~~$29.2 million, ~~$19.4~~$4.1 million, and ~~$10.6~~$2.2 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, would have offset the declines in oil, gas, and NGL production revenue by approximately ~~$53.0~~$22.6 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of ~~September 30, 2019,~~

March 31, 2020, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately ~~$92.2~~$54.1 million, ~~$8.1~~$16.1 million, and ~~$5.1~~$1.8 million, respectively.

Off-Balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, or through the filing of this report.

Critical Accounting Policies and Estimates

Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our ~~2018~~2019 Form 10-K for discussion of our accounting policies and estimates.

New Accounting Pronouncements

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

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in the Credit Agreement section in Overview of Liquidity and Capital Resources above. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our ~~sources of~~ liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default.

The following table provides reconciliations of our net ~~income (loss)~~loss (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(in thousands)												(in thousands)
Net income (loss) (GAAP)	$	42,234		$	(135,923	)	$	(84,946	)	$	198,675
Net loss (GAAP)													$	(411,895	)	$	(177,568	)
Interest expense	40,584			38,111			118,191			122,850			41,512			37,980
Income tax expense (benefit)	16,111			(36,748		)	(16,337		)	61,342
Income tax benefit													(99,008		)	(46,038		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	211,125			201,105			595,201			483,343			233,489			177,746
Exploration ⁽¹⁾	10,341			11,490			30,070			36,768			10,392			10,143
Abandonment and impairment of unproved properties	6,337			9,055			25,092			26,615
Impairment													989,763			6,338
Stock-based compensation expense	6,766			7,004			18,758			17,680			5,561			5,838
Net derivative (gain) loss	(100,889		)	178,026			(3,463		)	249,304			(545,340		)	177,081
Derivative settlement gain (loss)	24,722			(40,718		)	23,843			(101,911		)	73,437			(4,969		)
Net gain on divestiture activity	—			(786		)	(323		)	(425,656		)	—			(61		)
Loss on extinguishment of debt	—			26,722			—			26,722
Gain on extinguishment of debt													(12,195		)	—
Other, net	434			(1,265		)	1,129			(4,519		)	333			4
Adjusted EBITDAX (non-GAAP)	257,765			256,073			707,215			691,213			286,049			186,494
Interest expense	(40,584		)	(38,111		)	(118,191		)	(122,850		)	(41,512		)	(37,980		)
Income tax (expense) benefit	(16,111		)	36,748			16,337			(61,342		)
Income tax benefit													99,008			46,038
Exploration ⁽¹⁾	(10,341		)	(11,490		)	(30,070		)	(36,768		)	(10,392		)	(10,143		)
Amortization of debt discount and deferred financing costs	3,921			3,792			11,554			11,542			3,992			3,789
Deferred income taxes	19,617			(36,833		)	(13,620		)	60,672			(99,347		)	(47,003		)
Other, net	(1,438		)	1,483			(3,420		)	2,435			(1,149		)	(2,534		)
Net change in working capital	(9,673		)	17,997			11,781			(3,725		)	(18,517		)	(20,159		)
Net cash provided by operating activities (GAAP)	$	203,156		$	229,659		$	581,586		$	541,177		$	218,132		$	118,502

⁽¹⁾

Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

~~Cautionary Information about Forward-Looking Statements~~

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

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

~~any changes to the borrowing base or aggregate lender commitments under our Credit Agreement;~~

~~our outlook on future oil, gas, and NGL prices, well costs, service costs, and general and administrative costs;~~

the drilling of wells and other exploration and development activities and plans by us, our joint development partners, and/or other third-party operators, as well as possible or expected acquisitions or divestitures;

~~the possible divestiture or farm-down of, or joint venture relating to, certain properties;~~

~~proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;~~

~~future oil, gas, and NGL production estimates;~~

~~cash flows, anticipated liquidity, interest and related debt service expenses, changes in the Company’s effective tax rate, and the future repayment of debt;~~


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

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Some of these risks are described in the ~~Risk Factors~~ ~~section in Part I, Item 1A of our 2018 Form 10-K, and include without limitation such factors as:~~

~~domestic and foreign supply of oil, natural gas, and NGLs;~~

the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;

~~weakness in economic conditions, consumer demand, and uncertainty in financial markets;~~

~~our ability to replace reserves in order to sustain production;~~

~~our ability to raise the substantial amount of capital required to develop and/or replace our reserves;~~

~~our ability to compete against competitors that have greater financial, technical, and human resources;~~

~~our ability to attract and retain key personnel;~~

the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves, and that development of our proved undeveloped reserves may take longer and may require greater capital expenditures than we anticipate;

~~the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;~~

~~the possibility that exploration and development drilling may not result in commercially producible reserves;~~

~~our limited control over activities on outside-operated properties;~~

~~our reliance on the skill, expertise and availability of third-party service providers and equipment for our operated activities;~~

~~the possibility that title to properties in which we claim an interest may be defective;~~

our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;

the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including our success in integrating new assets, and whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;

~~the uncertainties associated with enhanced recovery methods;~~

~~our commodity derivative contracts expose us to counterparty credit risk and may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;~~

~~the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;~~

~~our ability to deliver required quantities of oil, gas, NGL, or water to contractual counterparties;~~

~~price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;~~

~~the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;~~

the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;

the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and Senior Convertible Notes may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions or lead to the accelerated payment of our debt;

~~the possibility of security threats, including terrorist attacks and cybersecurity attacks and breaches, against, or otherwise impacting, our facilities and systems;~~

~~operating and environmental risks and hazards that could result in substantial losses;~~

~~the impact of extreme weather conditions, laws and regulations, and lease stipulations on our ability to conduct drilling activities;~~

~~our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;~~

~~complex laws and regulations, including environmental regulations, that result in substantial costs, delays, and other risks;~~

~~the availability and capacity of gathering, transportation, processing, and/or refining facilities;~~

~~our ability to sell and/or receive market prices for our oil, gas, and NGLs;~~

~~new technologies may cause our current exploration and drilling methods to become obsolete; and~~

~~litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.~~

We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under the captions Interest Rate Risk and Commodity Price Risk in Item 2 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place ~~under~~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 ~~2018~~2019 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

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

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

Changes in Internal Control Over Financial Reporting

There have been no changes during the ~~third~~first quarter of ~~2019~~2020 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

From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are expected to have a materially adverse effect upon our financial condition, results of operations or cash flows.

SPM NAM LLC. et al., v. SM Energy Company, Case No. 2018-07160, in the 189th Judicial District of Harris County, Texas.The case remains in discovery and the original trial date of June 22, 2020 has been postponed in light of the global COVID-19 pandemic. As of the filing of this report, the trial is expected to begin during the fourth quarter of 2020. Please refer to Legal Proceedings in Part I, Item 3 of the 2019 Form 10-K for additional detail regarding this case.

Other than as described above, there have been no material changes to the legal proceedings as previously disclosed in our 2019 Form 10-K.

ITEM 1A. RISK FACTORS

The global COVID-19 pandemic has impacted and will likely continue to impact us, and could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.

Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies around the world, including the oil, gas and NGL industry in which we operate. The rapid spread of the virus has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel, and other public health and safety measures, nearly all of which have materially reduced global demand for crude oil. The extent to which the global COVID-19 pandemic impacts will continue to affect our business, financial condition, liquidity, results of operations, prospects, and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information which may emerge concerning the severity of the global COVID-19 pandemic and the effectiveness of actions taken to contain the coronavirus or treat its impact now or in the future, among others.

Some impacts of the global COVID-19 pandemic that could have an adverse effect on our business, financial condition, liquidity and results of operations, include:

significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;

further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of the virus;

increased likelihood that we will, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut-in production, resulting from depressed oil prices, lack of storage, and other market or political forces;

increased costs associated with, or actual unavailability of, facilities for the storage of oil, gas and NGL production, in the markets in which we operate;

increased operational difficulties associated with, or an inability to, deliver oil and NGLs to end-markets, resulting from pipeline and storage constraints;

the potential for forced curtailment of oil and NGL production by state governmental agencies, resulting in a need to significantly curtail or shut-in our production;

the potential for loss of leasehold or asset value for failure to produce oil and gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or failures or difficulties in bringing shut-in wells back online at their prior production levels, or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing;

increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil and NGL production, resulting from adverse market conditions, a lack of access to capital and storage, and the failure of certain of our counterparties to continue as going concerns;

increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions;

decreased ability to access the capital markets or other sources of capital;

increased costs and staffing requirements related to facility modifications, social distancing measures or other best practices implemented in connection with federal, state or local government, and voluntarily imposed quarantines or other regulations or guidelines concerning physical gatherings; and

increased legal and operational costs related to compliance with significant changes in federal, state, and local laws and regulations.

To the extent the global COVID-19 pandemic continues to adversely affect the global economy, and/or adversely affects our business, financial condition, liquidity, results of operations and prospects it may also have the effect of increasing the likelihood and/or magnitude of other risks described in Risk Factors in Part I, Item 1A of our 2019 Form 10-K and in this Form 10-Q, including those risks related to market, credit, geopolitical and business operations, or risks described in our other filings with the SEC. In addition, the global COVID-19 pandemic, or any recurrence of the outbreak may also affect our business, operations or financial condition in a manner that is not presently known to us or that we currently do not expect to present a significant risk to our business, operations, or financial condition. Additionally, the extent and duration of the impacts of the competition between Russia and Saudi Arabia for crude oil market share and the global COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors and, as a result, there may be a less active trading market for our common stock, our stock price may be more volatile, and our ability to raise capital could be impaired. Any such future developments are dependent upon factors including, but are not limited to, the duration and spread of the outbreak, its severity, any recurrence of the outbreak, the actions to contain the virus or treat its impact, the size and effectiveness of the compensating measures taken by governments, and how quickly and to what extent normal economic and operating conditions can resume.

The ability or willingness of the Organization of the Petroleum Exporting Countries (“OPEC”), Russia and other oil exporting nations to set, maintain and enforce production levels has a significant impact on oil, gas and NGL commodity prices, which could have a material adverse effect on our business, financial condition, liquidity and results of operations.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC member countries, including those taken along with other oil exporting nations, have a significant impact on global oil supply and pricing. In March 2020, members of OPEC and ten other oil producing countries (“OPEC+”) met to discuss how to respond to the potential market effects of the global COVID-19 pandemic. The meeting ended on March 6, 2020, as Saudi Arabia failed to convince Russia to reduce production to offset falling demand due to slowing economic activity resulting from the global COVID-19 pandemic. In response to Russia’s refusal to accept the production cut, Saudi Arabia announced an immediate reduction in its export prices and Russia announced that all previously agreed oil production cuts would expire on April 1, 2020. These actions flooded the global market with an oversupply of crude oil, and led to an immediate and steep decrease in global oil prices. In early April 2020, in response to significantly depressed global oil prices, 23 countries, led by Saudi Arabia, Russia and the United States, committed to implement reductions in world oil production.

There can be no assurance that the production cuts will stabilize oil prices or that they will be maintained, and recent indications suggest that oil prices will be largely unaffected. The global COVID-19 pandemic has destroyed global oil demand to an unprecedented degree, and despite the concerted action to reduce global production, the relative magnitude of the production cuts as compared to the degree of demand destruction may be wholly insufficient to mitigate or even impact the over-supplied oil market. Further, there is a lack of transparency regarding production volumes among oil-producing nations, and there are limited enforcement mechanisms for real or perceived violations of the production cuts. In connection with past production cuts, OPEC has at times failed to enforce its own production limits on violating members, with no official mechanism for punishing member countries that do not comply. There can be no assurance that OPEC and non-OPEC member countries will abide by the quotas or that OPEC will enforce the quotas. Additionally, certain other countries with free-market economies that agreed to reduce production, are unable to impose mandatory production cuts on non-OPEC oil producers operating in their countries, but instead expect to realize a decrease in production through market forces, as companies tend to cut production voluntarily when prices drop. For such countries, there can be no assurance that oil producers will react in the desired manner or that the market will behave as expected. Uncertainty regarding the effectiveness and enforcement of the production cuts is likely to lead to increased volatility in the supply and demand of oil and the price of oil, all of which could have a material adverse effect on our business, financial condition, liquidity and results of operations.

We face risks associated with the forced curtailment of our production by state governmental agencies or others, which could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.

The Railroad Commission of Texas (the “Railroad Commission”) is a state agency that regulates oil and gas production in the state of Texas and has the power to curb production by private producers in order to conserve the state of Texas’ natural resources, to protect correlative rights and prevent waste, a power referred to as “proration.” As a result of the global COVID-19 pandemic and resulting oversupply of oil production and related significantly decreased prices, in April 2020, the Railroad Commission met to consider proration. As of the filing of this report, the Railroad Commission has not implemented proration, but is continuing to assess whether to invoke the power to enforce production limits to help stabilize the price of oil. At present, our investment portfolio is focused on high quality oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in South Texas. If the Railroad Commission implements proration in the state of Texas, any reduction in the level of our oil and NGL production could have a material adverse effect on our business, financial condition, liquidity and results of operations.

We may also be forced to curtail our production in response to the declining overall market for our production related to diminishing storage capacity available to the purchasers of our production, or to reduce economic loss.

If we cannot continue to meet the continued listing requirements of the New York Stock Exchange (the “NYSE”), the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock and allow holders of our Senior Convertible Notes to require us to repurchase their notes.

Pursuant to the NYSE Listed Company Manual, a company will be considered to be out of compliance with the NYSE’s continued listing standards if the average trading price of its common stock over any consecutive 30-trading-day period falls below $1.00 per share, which is the minimum average closing price required to maintain listing on the NYSE. While we continue to maintain compliance with the minimum average closing price required to maintain listing on the NYSE through the filing of this report, if we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-day period, the NYSE may delist our common stock for failure to maintain compliance with the NYSE price criteria listing standards. NYSE rules provide issuers six months from NYSE notification of a deficiency to cure noncompliance with the stock price listing standard before the NYSE begins suspension and delisting procedures. An issuer can regain compliance at any time during the six-month cure period if, on the last trading day of any calendar month during the cure period, the company has a closing stock price of at least $1.00 and an average closing stock price of at least $1.00 over the 30-trading-day period ending on the last trading day of that month. However, there can be no assurance that we would be able to regain compliance during such cure period.

A delisting of our common stock from the NYSE could negatively impact us by, among other things: reducing the liquidity and market price of our common stock; reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; decreasing the number of equity analysts that cover and report on our common stock, which could further reduce the number of investors willing to hold or acquire our common stock; and limiting our ability to issue additional securities or obtain additional financing in the future. In addition, delisting from the NYSE is likely to negatively impact our reputation and, as a consequence, our business.

Further, if our common stock is delisted by the NYSE (and we are not eligible to become listed on other specified exchanges), holders of our Senior Convertible Notes would have a right to require us to repurchase the Senior Convertible Notes at a purchase price equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon. As of March 31, 2020, $172.5 million aggregate principal amount of the Senior Convertible Notes was outstanding, and there can be no assurance we would have sufficient funds available to us to repurchase the Senior Convertible Notes put to us if required to do so in connection with a delisting. Failure to repurchase the Senior Convertible Notes put to us could, subject to a 60-day right to cure set forth in the supplemental indenture governing the Senior Convertible Notes, result in (a) an event of default under the supplemental indenture, and (b) the potential acceleration of our obligation to repay all outstanding Senior Convertible Notes, and could cause a cross-default under our other outstanding indebtedness, which could result in the foreclosure on the collateral securing our secured debt. As a result, we could be forced into bankruptcy or liquidation.

The depressed price of our common stock and market capitalization, resulting from the current macroeconomic environment and historically low commodity prices, could cause the Company to be subject to an unsolicited or hostile acquisition bid, which could result in substantial costs and diversion of management attention.

Due to the currently constrained macroeconomic environment and historically low commodity prices, the price of our common stock and market capitalization are significantly depressed. A relatively low stock price may cause us to become subject to an unsolicited or hostile acquisition bid, or other change in control. There can be no assurance that a third-party will not make an unsolicited takeover proposal in the future or take other action to acquire control of us or to otherwise influence our management and policies. Although we have certain anti-takeover measures in place, we have not adopted a shareholder rights plan, commonly known as a poison pill. The lack of this particular anti-takeover measure could make a change in control of us easier to accomplish.

Considering and responding to any future acquisition proposal or other stockholder action designed to acquire control, including the litigation that often accompanies such actions, is likely to be costly and time-consuming. Evaluating and addressing these overtures would require the time and attention of our management and Board of Directors, divert them from their focus on our business, and require us to incur additional expenses on outside legal, financial and other advisors, all of which could materially and adversely affect our business, financial condition and results of operations. Further, in the event that such an unsolicited or hostile bid is publicly disclosed, it may result in increased speculation and volatility in the price of our common stock.

There have been no other material changes to the risk factors as previously disclosed in our ~~2018~~2019 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, 2019,~~March 31, 2020, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act:

											PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
Period	Total Number of Shares Purchased ⁽¹⁾	Weighted Average Price Paid per 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⁾	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⁾
07/01/2019 - 07/31/2019	130,992	$	12.52	—	3,072,184
08/01/2019 - 08/31/2019	—	$	—	—	3,072,184
09/01/2019 - 09/30/2019	—	$	—	—	3,072,184
01/01/2020 - 01/31/2020						175	$	11.83	—	3,072,184
02/01/2020 - 02/29/2020						—	$	—	—	3,072,184
03/01/2020 - 03/31/2020						166	$	6.17	—	3,072,184
Total:	130,992	$	12.52	—	3,072,184	341	$	9.07	—	3,072,184


⁽¹⁾	All shares purchased by us in the ~~third~~first quarter of ~~2019~~2020 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs issued under the terms of award agreements granted under the Equity ~~Incentive Compensation~~ Plan.

⁽²⁾

In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. During the three months ended March 31, 2020, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of 2020.

Our payment of cash dividends to our stockholders is subject to certain covenants under the terms of our Credit Agreement, Senior Notes, and Senior Convertible Notes. Based on our current performance, we do not anticipate that any of these covenants will limit our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.

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)
~~10.1~~10.1*		~~First~~Third Amendment to Sixth Amended and Restated Credit Agreement, dated April ~~18, 2019~~29, 2020, among SM Energy Company, each of the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent ~~and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April 18, 2019, and incorporated herein by reference)~~
~~10.2†~~		~~Performance Share Unit Award Agreement as of July 1, 2019~~
~~10.3~~		Second Amendment to Sixth Amended and Restated Credit Agreement, dated September 19, 2019 among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on September 24, 2019, 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 ~~hereunto~~thereunto duly authorized.



	SM ENERGY COMPANY

~~November 1, 2019~~April 29, 2020	By:	/s/ JAVAN D. OTTOSON
		Javan D. Ottoson
		President and Chief Executive Officer
		(Principal Executive Officer)

~~November 1, 2019~~April 29, 2020	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

~~November 1, 2019~~April 29, 2020	By:	/s/ PATRICK A. LYTLE
		Patrick A. Lytle
		Controller and Assistant Secretary
		(Principal Accounting Officer)

4745



	Midland Basin						South Texas						Rocky Mountain						Total
	Nine Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
	(in thousands)
Oil production revenue	$	791,055		$	703,516		$	45,007		$	56,365		$	—		$	54,851		$	836,062		$	814,732
Gas production revenue	49,821			96,974			144,563			161,414			—			1,595			194,384			259,983
NGL production revenue	102			816			106,201			167,505			—			790			106,303			169,111
Total	$	840,978		$	801,306		$	295,771		$	385,284		$	—		$	57,236		$	1,136,749		$	1,243,826
Relative percentage	74		%	64		%	26		%	31		%	—		%	5		%	100		%	100		%



	PSUs ⁽¹⁾		Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	1,711,259		$	20.68
Granted	793,125		$	12.80
Vested	(346,021	)	$	26.31
Forfeited	(40,999	)	$	17.96
Non-vested at end of quarter	2,117,364		$	16.86



	RSUs		Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	1,243,163		$	21.50
Granted	978,932		$	12.36
Vested	(466,535	)	$	21.93
Forfeited	(111,188	)	$	19.94
Non-vested at end of quarter	1,644,372		$	16.04



	Midland Basin				South Texas				Rocky Mountain ⁽¹⁾				Total
	Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018		2019		2018		2019		2018
Production:
Oil (MMBbl)	14.8		11.8		0.9		1.0		—		0.9		15.7		13.7
Gas (Bcf)	24.4		18.9		57.3		57.6		—		1.2		81.7		77.7
NGLs (MMBbl)	—		—		6.2		5.9		—		—		6.2		6.0
Equivalent (MMBOE)	18.8		15.0		16.7		16.5		—		1.1		35.5		32.6
Avg. daily equivalents (MBOE/d)	69.0		54.9		61.1		60.4		—		4.1		130.1		119.4
Relative percentage	53	%	46	%	47	%	51	%	—	%	3	%	100	%	100	%

1775 Sherman Street, Suite 1200,

(Address of principal executive offices)

~~(Zip~~(Zip Code)