Commission File No. 001-35049

~~_________________________________________________________~~

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

_________________________________________________________

Delaware

84-0592823


~~Delaware~~		~~84-0592823~~
(State or other jurisdiction		(I.R.S Employer
of incorporation or organization)		Identification No.)

1400 Woodloch Forest Drive, Suite 300

The Woodlands, Texas 77380

(Address of principal executive offices)

Registrant’s telephone number, including area code: (281) 298-4246

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, $0.001 par value per share	ESTE	New York Stock Exchange ~~(NYSE)~~

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the ~~past~~preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to ~~post~~submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See 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~~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 ☒

As of ~~November 1, 2019, 29,305,986~~October 29, 2020, 30,210,749 shares of Class A Common Stock, $0.001 par value per share, and ~~35,260,680~~35,009,371 shares of Class B Common Stock, $0.001 par value per share, were outstanding.

Table of Contents

TABLE OF CONTENTS



			Page

		PART I – FINANCIAL INFORMATION

Item 1.		Financial Statements (Unaudited)	43
		Condensed Consolidated Balance Sheets as of September 30, ~~2019~~2020 and December 31, ~~2018~~2019	43
		Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, ~~2019~~2020 and ~~2018~~2019	64
		Condensed Consolidated Statements of Equity for the Nine Months Ended September 30, ~~2019~~2020 and ~~2018~~2019	75
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, ~~2019~~2020 and ~~2018~~2019	97
		Notes to Unaudited Condensed Consolidated Financial Statements	108
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	2119
Item 3.		Quantitative and Qualitative Disclosures About Market Risk	3328
Item 4.		Controls and Procedures	3328

		PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	29
Item 1.1A.	Risk Factors	~~Legal Proceedings~~29	34
~~Item 1A.~~		~~Risk Factors~~	34
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds	3429
Item 3.		Defaults Upon Senior Securities	3429
Item 4.		Mine Safety Disclosures	3429
Item 5.		Other Information	3429
Item 6.	Exhibits	~~Exhibits~~30	35
	Signatures	~~Signatures~~31	36

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except share and per share amounts)

	*September 30,*			*December 31,*
ASSETS	*2020*			*2019*
Current assets:
Cash	$	5,311		$	13,822
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues		12,097			29,047
Joint interest billings and other, net of allowance of $80 and $83 at September 30, 2020 and December 31, 2019, respectively		11,548			6,672
Derivative asset		25,097			8,860
Prepaid expenses and other current assets		1,560			1,867
Total current assets		55,613			60,268

Oil and gas properties, successful efforts method:
Proved properties		995,666			970,808
Unproved properties		236,482			260,271
Land		5,382			5,382
Total oil and gas properties		1,237,530			1,236,461
Accumulated depreciation, depletion and amortization		(271,012	)		(195,567	)
Net oil and gas properties		966,518			1,040,894

Other noncurrent assets:
Goodwill		0			17,620
Office and other equipment, net of accumulated depreciation and amortization of $3,558 and $3,180 at September 30, 2020 and December 31, 2019, respectively		1,044			1,311
Derivative asset		4,727			770
Operating lease right-of-use assets		2,769			3,108
Other noncurrent assets		1,331			1,572
TOTAL ASSETS	$	1,032,002		$	1,125,543
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	6,910		$	25,284
Revenues and royalties payable		28,047			35,815
Accrued expenses		12,844			19,538
Asset retirement obligation		308			308
Derivative liability		1,040			6,889
Advances		93			11,505
Operating lease liabilities		768			570
Finance lease liabilities		96			206
Other current liabilities		11			43
Total current liabilities		50,117			100,158

Noncurrent liabilities:
Long-term debt		130,000			170,000
Deferred tax liability		15,294			15,154
Asset retirement obligation		2,027			1,856
Derivative liability		577			0
Operating lease liabilities		2,001			2,539
Finance lease liabilities		15			85
Other noncurrent liabilities		138			0
Total noncurrent liabilities		150,052			189,634

Commitments and Contingencies (Note 13)

Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding		0			0
Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 30,210,749 and 29,421,131 issued and outstanding at September 30, 2020 and December 31, 2019, respectively		30			29
Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 35,009,371 and 35,260,680 issued and outstanding at September 30, 2020 and December 31, 2019, respectively		35			35
Additional paid-in capital		537,990			527,246
Accumulated deficit		(186,787	)		(181,711	)
Total Earthstone Energy, Inc. equity		351,268			345,599
Noncontrolling interest		480,565			490,152
Total equity		831,833			835,751
TOTAL LIABILITIES AND EQUITY	$	1,032,002		$	1,125,543

September 30, December 31,
ASSETS 2019 2018
Current assets:
Cash $ 9,816
$ 376
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues 14,990
13,683
Joint interest billings and other, both net of allowance of $134 8,001
4,166
Derivative asset 20,179
43,888
Prepaid expenses and other current assets 2,488
1,443
Total current assets 55,474
63,556

Oil and gas properties, successful efforts method:
Proved properties 904,323
755,443
Unproved properties 269,417
266,140
Land 5,382
5,382
Total oil and gas properties 1,179,122
1,026,965

Accumulated depreciation, depletion and amortization (168,988 ) (127,256 )
Net oil and gas properties 1,010,134
899,709

Other noncurrent assets:
Goodwill 17,620
17,620
Office and other equipment, net of accumulated depreciation and amortization of $3,033 and $2,490 at September 30, 2019 and December 31, 2018, respectively 1,350
662
Derivative asset 9,246
21,121
Operating lease right-of-use assets 3,295
—
Other noncurrent assets 1,532
1,640
TOTAL ASSETS $ 1,098,651
$ 1,004,308
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 37,405
$ 26,452
Revenues and royalties payable 19,706
28,748
Accrued expenses 35,604
22,406
Asset retirement obligation 420
557
Advances 20,894
3,174
Derivative liability 137
528
Operating lease liabilities 586
—
Finance lease liabilities 256
—
Total current liabilities 115,008
81,865

Noncurrent liabilities:
Long-term debt 125,000
78,828
Deferred tax liability 14,217
13,489
Asset retirement obligation 1,833
1,672
Derivative liability 29
1,891
Operating lease liabilities 2,722
—

Finance lease liabilities 111
—
Other noncurrent liabilities —
71
Total noncurrent liabilities 143,912
95,951

Commitments and Contingencies (Note 12)

Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding —
—
Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 29,150,220 and 28,696,321 issued and outstanding at September 30, 2019 and December 31, 2018, respectively 29
29
Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 35,416,446 and 35,452,178 issued and outstanding at September 30, 2019 and December 31, 2018, respectively 35
35
Additional paid-in capital 523,402
517,073
Accumulated deficit (179,087 ) (182,497 )
Total Earthstone Energy, Inc. equity 344,379
334,640
Noncontrolling interest 495,352
491,852
Total equity 839,731
826,492

TOTAL LIABILITIES AND EQUITY $ 1,098,651
$ 1,004,308

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

Table of Contents

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except share and per share amounts)

	*Three Months Ended*						*Nine Months Ended*
	*September 30,*						*September 30,*
	*2020*			*2019*			*2020*			*2019*
REVENUES
Oil	$	33,158		$	35,443		$	93,017		$	111,657
Natural gas		2,642			903			4,855			2,126
Natural gas liquids		5,247			2,858			9,976			10,691
Total revenues		41,047			39,204			107,848			124,474

OPERATING COSTS AND EXPENSES
Lease operating expense		7,044			6,419			21,971			20,485
Production and ad valorem taxes		2,696			2,698			7,198			8,001
Rig termination expense		0			0			426			0
Depreciation, depletion and amortization		28,538			14,079			76,096			42,281
Impairment expense		2,115			0			62,548			0
General and administrative expense		5,796			6,057			19,615			19,948
Transaction costs		(705	)		215			(324	)		797
Accretion of asset retirement obligation		47			52			137			160
Exploration expense		0			0			298			0
Total operating costs and expenses		45,531			29,520			187,965			91,672

(Loss) gain on sale of oil and gas properties		0			(120	)		198			(446	)

(Loss) income from operations		(4,484	)		9,564			(79,919	)		32,356

OTHER INCOME (EXPENSE)
Interest expense, net		(1,186	)		(1,609	)		(4,207	)		(4,735	)
(Loss) gain on derivative contracts, net		(6,040	)		18,726			73,065			(19,672	)
Other income (expense), net		(18	)		21			120			(1	)
Total other income (expense)		(7,244	)		17,138			68,978			(24,408	)

(Loss) income before income taxes		(11,728	)		26,702			(10,941	)		7,948
Income tax expense		(130	)		(575	)		(112	)		(728	)
Net (loss) income		(11,858	)		26,127			(11,053	)		7,220

Less: Net (loss) income attributable to noncontrolling interest		(6,413	)		14,357			(5,977	)		3,877

Net (loss) income attributable to Earthstone Energy, Inc.	$	(5,445	)	$	11,770		$	(5,076	)	$	3,343

Net (loss) income per common share attributable to Earthstone Energy, Inc.:
Basic	$	(0.18	)	$	0.41		$	(0.17	)	$	0.12
Diluted	$	(0.18	)	$	0.41		$	(0.17	)	$	0.12

Weighted average common shares outstanding:
Basic		30,073,635			29,032,842			29,810,705			28,883,907
Diluted		30,073,635			29,032,842			29,810,705			28,883,907

Three Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018
REVENUES
Oil $ 35,443
$ 38,791
$ 111,657
$ 105,111
Natural gas 903
1,790
2,126
6,257
Natural gas liquids 2,858
5,495
10,691
12,753
Total revenues 39,204
46,076
124,474
124,121

OPERATING COSTS AND EXPENSES
Lease operating expense 7,259
4,843
22,531
14,509
Severance taxes 1,858
2,254
5,955
6,115
Impairment expense —
833
—
833
Depreciation, depletion and amortization 14,079
12,842
42,281
33,362
General and administrative expense 6,230
4,944
20,528
18,809
Transaction costs 42
892
217
892
Accretion of asset retirement obligation 52
44
160
128
Total operating costs and expenses 29,520
26,652
91,672
74,648

(Loss) gain on sale of oil and gas properties (120 ) 4,096
(446 ) 4,608

Income from operations 9,564
23,520
32,356
54,081

OTHER INCOME (EXPENSE)
Interest expense, net (1,609 ) (565 ) (4,735 ) (1,788 )
Gain (loss) on derivative contracts, net 18,726
(17,481 ) (19,672 ) (33,606 )
Litigation settlement —
(4,775 ) —
(4,775 )
Other income (expense), net 21
37
(1 ) 434
Total other income (expense) 17,138
(22,784 ) (24,408 ) (39,735 )

Income before income taxes 26,702
736
7,948
14,346
Income tax expense (575 ) (172 ) (728 ) (119 )
Net income 26,127
564
7,220
14,227

Less: Net income attributable to noncontrolling interest 14,357
340
3,877
8,032

Net income attributable to Earthstone Energy, Inc. $ 11,770
$ 224
$ 3,343
$ 6,195

Net income per common share attributable to Earthstone Energy, Inc.:
Basic $ 0.41
$ 0.01
$ 0.12
$ 0.22
Diluted $ 0.41
$ 0.01
$ 0.12
$ 0.22

Weighted average common shares outstanding:
Basic 29,032,842
28,257,376
28,883,907
28,011,298
Diluted 29,032,842
28,311,759
28,883,907
28,108,365

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

Table of Contents

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)

(In thousands, except share amounts)

	*Issued Shares*
	*Class A Common Stock*			*Class B Common Stock*			*Class A Common Stock*		*Class B Common Stock*		*Additional Paid-in Capital*			*Accumulated Deficit*			*Total Earthstone Energy, Inc. Equity*			*Noncontrolling Interest*			*Total Equity*
At December 31, 2019		29,421,131			35,260,680		$	29	$	35	$	527,246		$	(181,711	)	$	345,599		$	490,152		$	835,751
Stock-based compensation expense		—			—			0		0		2,694			0			2,694						2,694
Vesting of restricted stock units, net of taxes paid		231,834			0			1		0		0			0			1			0			1
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings		75,695			0			0		0		(214	)		0			(214	)		0			(214	)
Cancellation of treasury shares		(75,695	)		0			—		—		—			—			—			—			—
Class B Common Stock converted to Class A Common Stock		199,993			(199,993	)		0		0		2,897			0			2,897			(2,897	)		0
Net income		—			—			0		0		0			16,708			16,708			20,006			36,714
At March 31, 2020		29,852,958			35,060,687		$	30	$	35	$	532,623		$	(165,003	)	$	367,685		$	507,261		$	874,946
Stock-based compensation expense		—			—			0		0		2,568			0			2,568			0			2,568
Vesting of restricted stock units, net of taxes paid		165,399			0			0		0		0			0			0			0			0
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings		57,810			0			0		0		(170	)		0			(170	)		0			(170	)
Cancellation of treasury shares		(57,810	)		0			—		—		—			—			—			—			—
Class B Common Stock converted to Class A Common Stock		2,000			(2,000	)		0		0		28			0			28			(28	)		0
Net loss		—			—			0		0		0			(16,339	)		(16,339	)		(19,570	)		(35,909	)
At June 30, 2020		30,020,357			35,058,687		$	30	$	35	$	535,049		$	(181,342	)	$	353,772		$	487,663		$	841,435
Stock-based compensation expense		—			—			0		0		2,403			0			2,403			0			2,403
Vesting of restricted stock units, net of taxes paid		141,076			0			0		0		0			0			0			0			0
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings		54,268			0			0		0		(147	)		0			(147	)		0			(147	)
Cancellation of treasury shares		(54,268	)		0			—		—		—			—			—			—			—
Class B Common Stock converted to Class A Common Stock		49,316			(49,316	)		0		0		685			0			685			(685	)		0
Net loss		—			—			0		0		0			(5,445	)		(5,445	)		(6,413	)		(11,858	)
At September 30, 2020		30,210,749			35,009,371		$	30	$	35	$	537,990		$	(186,787	)	$	351,268		$	480,565		$	831,833

Issued Shares
Class A Common Stock Class B Common Stock Class A Common Stock Class B Common Stock Additional Paid-in Capital Accumulated Deficit Total Earthstone Energy, Inc. Equity Noncontrolling Interest Total Equity
At December 31, 2018 28,696,321
35,452,178
$ 29
$ 35
$ 517,073
$ (182,497 ) $ 334,640
$ 491,852
$ 826,492
ASC 842 implementation —
—
—
—
—
67
67
99
166
Stock-based compensation expense —
—
—
—
2,212
—
2,212
2,212
Vesting of restricted stock units, net of taxes paid 166,140
—
—
—
—
—
—
—
—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings 59,261
—
—
—
(396 ) —
(396 ) —
(396 )
Cancellation of treasury shares (59,261 ) —
—
—
—
—
—
—
—
Net loss —
—
—
—
—
(17,204 ) (17,204 ) (21,239 ) (38,443 )
At March 31, 2019 28,862,461
35,452,178
$ 29
$ 35
$ 518,889
$ (199,634 ) $ 319,319
$ 470,712
$ 790,031
Stock-based compensation expense —
—
—
—
2,261
—
2,261
2,261
Vesting of restricted stock units, net of taxes paid 133,311
—
—
—
—
—
—
—
—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings 43,344
—
—
—
(265 ) —
(265 ) —
(265 )
Cancellation of treasury shares (43,344 ) —
—
—
—
—
—
—
—
Class B Common Stock converted to Class A Common Stock 35,732
(35,732 ) —
—
476
—
476
(476 ) —
Net income —
—
—
—
—
8,777
8,777
10,759
19,536
At June 30, 2019 29,031,504
35,416,446
$ 29
$ 35
$ 521,361
$ (190,857 ) $ 330,568
$ 480,995
$ 811,563
Stock-based compensation expense —
—
—
—
2,207
—
2,207
2,207
Vesting of restricted stock units, net of taxes paid 118,716
—
—
—
—
—
—
—
—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings 49,111
—
—
—
(166 ) —
(166 ) —
(166 )
Cancellation of treasury shares (49,111 ) —
—
—
—
—
—
—
—
Net income —
—
—
—
—
11,770
11,770
14,357
26,127
At September 30, 2019 29,150,220
35,416,446
$ 29
$ 35
$ 523,402
$ (179,087 ) $ 344,379
$ 495,352
$ 839,731

Issued Shares
Class A Common Stock Class B Common Stock Class A Common Stock Class B Common Stock Additional Paid-in Capital Accumulated Deficit Total Earthstone Energy, Inc. Equity Noncontrolling Interest Total Equity
At December 31, 2017 27,584,638
36,052,169
$ 28
$ 36
$ 503,932
$ (224,822 ) $ 279,174
$ 446,558
$ 725,732
Stock-based compensation expense —
—
—
—
1,940
—
1,940
1,940
Vesting of restricted stock units, net of taxes paid 86,272
—
—
—
—
—
—
—
—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings 28,664
—
—
—
(466 ) —
(466 ) —
(466 )
Cancellation of treasury shares (28,664 ) —
—
—
—
—
—
—
—
Class B Common Stock converted to Class A Common Stock 194,046
(194,046 ) —
—
2,409
—
2,409
(2,409 ) —
Net income —
—
—
—
—
5,321
5,321
6,870
12,191
At March 31, 2018 27,864,956
35,858,123
$ 28
$ 36
$ 507,815
$ (219,501 ) $ 288,378
$ 451,019
$ 739,397
Stock-based compensation expense —
—
—
—
2,073
—
2,073
2,073
Vesting of restricted stock units, net of taxes paid 255,313
—
—
—
—
—
—
—
—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings 83,762
—
—
—
(648 ) —
(648 ) —
(648 )
Cancellation of treasury shares (83,762 ) —
—
—
—
—
—
—
—
Class B Common Stock converted to Class A Common Stock 11,195
(11,195 ) —
—
141
—
141
(141 ) —
Net income —
—
—
—
—
650
650
822
1,472
At June 30, 2018 28,131,464
35,846,928
28
36
509,381
(218,851 ) 290,594
451,700
742,294
Stock-based compensation expense —
—
—
—
1,522
—
1,522
1,522
Vesting of restricted stock units, net of taxes paid 85,063
—
—
—
—
—
—
—
—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings 30,511
—
—
—
(287 ) —
(287 ) —
(287 )
Cancellation of treasury shares (30,511 ) —
—
—
—
—
—
—
—
Class B Common Stock converted to Class A Common Stock 183,894
(183,894 ) —
—
2,344
—
2,344
(2,344 ) —
Net income —
—
—
—
—
224
224
340
564
At September 30, 2018 28,400,421
35,663,034
$ 28
$ 36
$ 512,960
$ (218,627 ) $ 294,397
$ 449,696
$ 744,093

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

~~EARTHSTONE ENERGY, INC.~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)~~

~~(In thousands)~~

For the Nine Months Ended
September 30,
2019 2018
Cash flows from operating activities:
Net income $ 7,220
$ 14,227
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties —
833
Depreciation, depletion and amortization 42,281
33,362
Accretion of asset retirement obligations 160
128
Settlement of asset retirement obligations (179 ) (79 )
Loss (gain) on sale of oil and gas properties 446
(4,608 )
Total loss on derivative contracts, net 19,672
33,606
Operating portion of net cash received (paid) in settlement of derivative contracts 13,660
(13,643 )
Stock-based compensation 6,680
5,535
Deferred income taxes 728
119
Amortization of deferred financing costs 336
228
Changes in assets and liabilities:
(Increase) decrease in accounts receivable (5,585 ) (1,476 )
(Increase) decrease in prepaid expenses and other current assets (28 ) (372 )
Increase (decrease) in accounts payable and accrued expenses (8,330 ) 3,939
Increase (decrease) in revenues and royalties payable (9,042 ) 26,572
Increase (decrease) in advances 17,720
(1,816 )
Net cash provided by operating activities 85,739
96,555
Cash flows from investing activities:
Additions to oil and gas properties (120,685 ) (120,124 )
Additions to office and other equipment (379 ) (121 )
Proceeds from sales of oil and gas properties 2
5,840
Net cash used in investing activities (121,062 ) (114,405 )
Cash flows from financing activities:
Proceeds from borrowings 165,272
70,308
Repayments of borrowings (119,099 ) (60,308 )
Cash paid related to the exchange and cancellation of Class A Common Stock (827 ) (1,402 )
Cash paid for finance leases (355 ) —
Deferred financing costs (228 ) (274 )
Net cash provided by financing activities 44,763
8,324
Net increase (decrease) in cash 9,440
(9,526 )
Cash at beginning of period 376
22,955
Cash at end of period $ 9,816
$ 13,429
Supplemental disclosure of cash flow information
Cash paid for:
Interest $ 4,235
$ 1,480
Non-cash investing and financing activities:
Accrued capital expenditures $ 50,615
$ 11,314
Lease asset additions - ASC 842 $ 4,710
$ —
Asset retirement obligations $ 43
$ (120 )

	*Issued Shares*
	*Class A Common Stock*			*Class B Common Stock*			*Class A Common Stock*		*Class B Common Stock*		*Additional Paid-in Capital*			*Accumulated Deficit*			*Total Earthstone Energy, Inc. Equity*			*Noncontrolling Interest*			*Total Equity*
At December 31, 2018		28,696,321			35,452,178		$	29	$	35	$	517,073		$	(182,497	)	$	334,640		$	491,852		$	826,492
ASC 842 implementation		—			—			0		0		0			67			67			99			166
Stock-based compensation expense		—			—			0		0		2,212			0			2,212			0			2,212
Vesting of restricted stock units, net of taxes paid		166,140			0			0		0		0			0			0			0			0
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings		59,261			0			0		0		(396	)		0			(396	)		0			(396	)
Cancellation of treasury shares		(59,261	)		0			—		—		—			—			—			—			—
Net loss		—			—			0		0		0			(17,204	)		(17,204	)		(21,239	)		(38,443	)
At March 31, 2019		28,862,461			35,452,178		$	29	$	35	$	518,889		$	(199,634	)	$	319,319		$	470,712		$	790,031
Stock-based compensation expense		—			—			0		0		2,261			0			2,261						2,261
Vesting of restricted stock units, net of taxes paid		133,311			0			0		0		0			0			0			0			0
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings		43,344			0			0		0		(265	)		0			(265	)		0			(265	)
Cancellation of treasury shares		(43,344	)		0			—		—		—			—			—			—			—
Class B Common Stock converted to Class A Common Stock		35,732			(35,732	)		0		0		476			0			476			(476	)		0
Net income		—			—			0		0		0			8,777			8,777			10,759			19,536
At June 30, 2019		29,031,504			35,416,446		$	29	$	35	$	521,361		$	(190,857	)	$	330,568		$	480,995		$	811,563
Stock-based compensation expense		—			—			0		0		2,207			0			2,207						2,207
Vesting of restricted stock units, net of taxes paid		118,716			0			0		0		0			0			0			0			0
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings		49,111			0			0		0		(166	)		0			(166	)		0			(166	)
Cancellation of treasury shares		(49,111	)		0			—		—		—			—			—			—			—
Class B Common Stock converted to Class A Common Stock		0			0			0		0		0			0			0			0			0
Net income		—			—			0		0		0			11,770			11,770			14,357			26,127
At September 30, 2019		29,150,220			35,416,446		$	29	$	35	$	523,402		$	(179,087	)	$	344,379		$	495,352		$	839,731

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

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EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

	*For the Nine Months Ended*
	*September 30,*
	*2020*			*2019*
Cash flows from operating activities:
Net (loss) income	$	(11,053	)	$	7,220
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		76,096			42,281
Impairment of proved and unproved oil and gas properties		44,928			0
Impairment of goodwill		17,620			0
Accretion of asset retirement obligations		137			160
Settlement of asset retirement obligations		0			(179	)
(Gain) loss on sale of oil and gas properties		(198	)		446
Total (gain) loss on derivative contracts, net		(73,065	)		19,672
Operating portion of net cash received in settlement of derivative contracts		47,599			13,660
Stock-based compensation		7,665			6,680
Deferred income taxes		112			728
Amortization of deferred financing costs		241			336
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		12,102			(5,585	)
(Increase) decrease in prepaid expenses and other current assets		(264	)		(28	)
Increase (decrease) in accounts payable and accrued expenses		1,976			(8,330	)
Increase (decrease) in revenues and royalties payable		(7,768	)		(9,042	)
Increase (decrease) in advances		(11,412	)		17,720
Net cash provided by operating activities		104,716			85,739
Cash flows from investing activities:
Additions to oil and gas properties		(72,869	)		(120,685	)
Additions to office and other equipment		(111	)		(379	)
Proceeds from sales of oil and gas properties		409			2
Net cash used in investing activities		(72,571	)		(121,062	)
Cash flows from financing activities:
Proceeds from borrowings		93,923			165,272
Repayments of borrowings		(133,923	)		(119,099	)
Cash paid related to the exchange and cancellation of Class A Common Stock		(531	)		(827	)
Cash paid for finance leases		(125	)		(355	)
Deferred financing costs		0			(228	)
Net cash (used in) provided by financing activities		(40,656	)		44,763
Net (decrease) increase in cash		(8,511	)		9,440
Cash at beginning of period		13,822			376
Cash at end of period	$	5,311		$	9,816
Supplemental disclosure of cash flow information
Cash paid for:
Interest	$	3,613		$	4,235
Non-cash investing and financing activities:
Accrued capital expenditures	$	2,213		$	50,615
Lease asset additions - ASC 842	$	0		$	4,710
Asset retirement obligations	$	44		$	43

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Basis of Presentation and Summary of Significant Accounting Policies

Earthstone Energy, Inc., a Delaware corporation ~~("Earthstone"~~(“Earthstone” and together with its consolidated subsidiaries, the ~~"Company"~~“Company”), is a growth-oriented independent oil and natural gas development and production company. In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities. The Company's operations are all in the upstream segment of the oil and natural gas industry and all its properties are onshore in the United States.

Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc., a Utah corporation (“Lynden US”) and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Condensed Consolidated Financial Statements representing the economic interests of EEH's members other than Earthstone and Lynden US.

The accompanying unaudited Condensed Consolidated Financial Statements and notes thereto have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to interim financial statements. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted. The accompanying unaudited Condensed Consolidated Financial Statements and notes should be read in conjunction with the financial statements and notes included in Earthstone’s ~~2018~~2019 Annual Report on Form ~~10-K.~~

10-K.

The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's financial position, results of operations and cash flows for the periods presented. The Company’s Condensed Consolidated Balance Sheet at December 31, ~~2018~~2019 is derived from the audited Consolidated Financial Statements at that date.

Certain prior period amounts have been reclassified to conform to current period presentation within the Condensed Consolidated Financial Statements. Prior period ad valorem taxes which were previously included in Lease operating expenses within the Operating Costs and Expenses section of the Condensed Consolidated Statements of Operations have been reclassified from Lease operating expenses and combined with the previously presented Severance taxes line-item and the combined total presented as Production and ad valorem taxes, also within Operating Costs and Expenses, in order to conform to current period presentation. Additionally, prior period legal expenses related to a previously completed transaction and previously included in General and administrative expense within Operating Costs and Expenses have been reclassified to Transaction costs, also within Operating Costs and Expenses, to conform to current period presentation. These reclassifications had no effect on Income from operations or any other subtotal in the Condensed Consolidated Statements of Operations.

Recently Issued Accounting Standards

~~Leases~~

Intangibles – Goodwill and Other – In ~~February 2016,~~ January 2017, the Financial Accounting Standards Board ~~("FASB"~~(“FASB”) issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent Accounting Standards Codification (“ASC”) Topic 842, Leases (“ASC Topic 842”).

ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company completed a comprehensive assessment of existing contracts, as well as future potential contracts, to determine the impact of the new accounting guidance on its consolidated financial statements and related disclosures. The evaluation process included review of contracts for drilling rigs, office facilities, compression services, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. The Company's evaluation process did not include review of its mineral leases as they are outside the scope of ASC Topic 842.

The Company adopted this guidance on January 1, 2019, the transition date, using the simplified transition method described in ASU 2018-11 which allows entities to continue to apply historical accounting guidance in the comparative periods presented in the year of adoption. Accordingly, prior period amounts in our financial statements are not adjusted and continue to be reported in accordance with historical accounting guidance.

The Company elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases. Additionally, the Company elected the practical expedient under ASU 2018-01 to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date.

~~The Company made an accounting policy election not to apply the lease recognition requirements to short-term leases.~~

The adoption of ASC Topic 842 did not have a material impact on the Company's financial statements, resulted in increases of less than 1% to each of its total assets and total liabilities on the balance sheet, and resulted in an immaterial decrease to accumulated deficit as of the beginning of 2019. See ~~Note 14. Leases~~ ~~for further information.~~

~~Table of Contents~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~Intangibles - Goodwill and Other –~~ ~~In January 2017, the FASB~~ issued updated guidance simplifying the test for goodwill impairment. The update eliminates ~~Step 2~~the requirement to determine the implied value of goodwill in measuring an impairment loss. Upon adoption, the measurement of a goodwill impairment ~~test. Instead, an entity should perform its annual or interim goodwill impairment test by comparing~~will represent the ~~fair value~~excess of ~~a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds~~ the reporting unit’s carrying value over its fair ~~value; however,~~value and will be limited to the ~~loss recognized should not exceed the total amount~~carrying value of ~~goodwill allocated to that reporting unit.~~goodwill. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The update is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. The Company isadopted the update effective January 1, 2020. See further discussion of goodwill in ~~the process of evaluating the impact of this guidance, if any, on its Consolidated Financial Statements.~~

Note 15. Goodwill.

Fair Value Measurements – In August 2018, the FASB issued an ~~update~~Accounting Standards Update (“ASU”) which modifies the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. The Company adopted the update effective January 1, 2020 and the impact was not material to the Condensed Consolidated Financial Statements.

Credit Losses - In June 2016, the FASB issued an update that requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance is effective for interim and annual periods beginning after December 15, 2019. The Company adopted the update effective January 1, 2020 and the impact was not material to the Condensed Consolidated Financial Statements.

Income Taxes - In December 2019, the FASB issued an update that simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020 and early adoption is permitted. The Company is in the process of evaluating the impact of this update, if any, on its Condensed Consolidated Financial Statements.

Reference Rate Reform - In March 2020, the FASB issued an update that provides optional guidance for a limited period of time to ease the transition from LIBOR to an alternative reference rate. The ASU intends to address certain concerns relating to accounting for contract modifications and hedge accounting. These optional expedients and exceptions to applying GAAP, assuming certain criteria are met, are allowed through December 31, 2022. The Company is currently evaluating the provisions of this update and has not yet determined whether it will elect the optional expedients. The Company does not expect the transition to an alternative rate to have a material impact on its business, operations or liquidity.

Table of Contents

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Fair Value Measurements

FASB ~~ASC~~Accounting Standards Codification (“ASC”) Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC 820 provides a framework for measuring fair value, establishes a ~~three-level~~three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.

The ~~three-level~~three-level fair value hierarchy for disclosure of fair value measurements defined by ASC 820 is as follows:

Level 1– Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2– Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3– Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the nine months ended September 30, ~~2019.~~

2020.

Fair Value on a Recurring Basis

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural ~~gas.~~gas and interest rate swaps. The Company’s commodity price hedges and interest rate swaps are valued based on a discounted future cash flow ~~model. The primary input for the model is~~models that are primarily based on published forward commodity price ~~curves. The swaps~~curves and published LIBOR forward curves; thus, these inputs are ~~also~~ designated as Level 2 within the valuation hierarchy.

The fair values of ~~commodity~~ derivative instruments in an asset ~~position~~positions include ~~a measure~~measures of counterparty nonperformance risk, and the fair values of ~~commodity~~ derivative instruments in a liability ~~position~~positions include ~~a measure~~measures of the Company’s nonperformance risk. These measurements were not material to the Condensed Consolidated Financial Statements.

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):

~~Table of Contents~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

September 30, 2019 Level 1 Level 2 Level 3 Total
Financial assets
Derivative asset - current $ —
$ 20,179
$ —
$ 20,179
Derivative asset - noncurrent —
9,246
—
9,246
Total financial assets $ —
$ 29,425
$ —
$ 29,425

Financial liabilities
Derivative liability - current $ —
$ 137
$ —
$ 137
Derivative liability - noncurrent —
29
—
29
Total financial liabilities $ —
$ 166
$ —
$ 166

December 31, 2018
Financial assets
Derivative asset - current $ —
$ 43,888
$ —
$ 43,888
Derivative asset - noncurrent

21,121

21,121
Total financial assets $ —
$ 65,009
$ —
$ 65,009

Financial liabilities
Derivative liability - current $ —
$ 528
$ —
$ 528
Derivative liability - noncurrent —
1,891
—
1,891
Total financial liabilities $ —
$ 2,419
$ —
$ 2,419

September 30, 2020	*Level 1*		*Level 2*		*Level 3*		*Total*
Financial assets
Derivative asset - current	$	0	$	25,097	$	0	$	25,097
Derivative asset - noncurrent		0		4,727		0		4,727
Total financial assets	$	0	$	29,824	$	0	$	29,824

Financial liabilities
Derivative liability - current	$	0	$	1,040	$	0	$	1,040
Derivative liability - noncurrent		0		577		0		577
Total financial liabilities	$	0	$	1,617	$	0	$	1,617

December 31, 2019
Financial assets
Derivative asset - current	$	0	$	8,860	$	0	$	8,860
Derivative asset - noncurrent		0		770		0		770
Total financial assets	$	0	$	9,630	$	0	$	9,630

Financial liabilities
Derivative liability - current	$	0	$	6,889	$	0	$	6,889
Derivative liability - noncurrent		0		0		0		0
Total financial liabilities	$	0	$	6,889	$	0	$	6,889

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.

Fair Value on a Nonrecurring Basis

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties, goodwill, business combinations, asset retirement obligations and performance units. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments ~~only~~if events or changes in certain circumstances ~~as described~~indicate that adjustments may be necessary. Due to significant declines in commodity prices and global demand for oil and natural gas products resulting from the ~~Notes to Consolidated Financial Statements included~~COVID-19 pandemic, the Company assessed the fair values of its oil and natural gas properties and goodwill resulting in ~~Earthstone’s 2018 Annual Report on Form 10-K.~~non-cash impairment charges during the nine months ended September 30, 2020. See further discussion in Note 4. Asset Impairments.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Derivative Financial Instruments

Commodity Derivative Instruments

The Company’s hedging activities primarily consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swap agreements. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Consistent with its hedging policy, the Company has entered into a series of derivative instruments to hedge a significant portion of its expected oil and natural gas production through December 31, 2021. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, the Company believes these instruments reduce its exposure to oil and natural gas price fluctuations and, thereby, allow the Company to achieve a more predictable cash flow.

The Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow related to a forecasted transaction. The Company does not enter into derivative instruments for trading or other speculative purposes. These transactions are recorded in the Condensed Consolidated Financial Statements in accordance with FASB ASC Topic 815. The Company has accounted for these transactions using the mark-to-market accounting method. Generally, the Company incurs accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Operations.

~~Table of Contents~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

The Company had the following open crude oil and natural gas derivative contracts as of September 30, ~~2019:~~

Price Swaps
Period Commodity
Volume
(Bbls / MMBtu)

Weighted Average Price
($/Bbl / $/MMBtu)
Q4 2019 Crude Oil 671,600
$ 64.31
Q1 - Q4 2020 Crude Oil 2,562,000
$ 61.26
Q1 - Q4 2021 Crude Oil 730,000
$ 55.00
Q4 2019 Crude Oil Basis Swap(1) 506,000
$ (5.29 )
Q4 2019 Crude Oil Basis Swap(2) 92,000
$ 4.50
Q1 - Q4 2020 Crude Oil Basis Swap(1) 2,562,000
$ (1.40 )
Q1 - Q4 2021 Crude Oil Basis Swap(1) 730,000
$ 0.85
Q4 2019 Natural Gas 782,000
$ 2.85
Q1 - Q4 2020 Natural Gas 2,562,000
$ 2.85
Q4 2019 Natural Gas Basis Swap(3) 782,000
$ (1.15 )
Q1 - Q4 2020 Natural Gas Basis Swap(3) 2,562,000
$ (1.07 )

2020:

	*Price Swaps*
		*Volume*		*Weighted Average Price*
Period	*Commodity*	*(Bbls / MMBtu)*		*($/Bbl / $/MMBtu)*
Q4 2020	Crude Oil		552,000	$	60.65
Q1 - Q4 2021	Crude Oil		1,460,000	$	55.16
Q4 2020	Crude Oil Basis Swap (1)		598,000	$	(1.50	)
Q4 2020	Crude Oil Basis Swap (2)		92,000	$	2.55
Q4 2020	Crude Oil Roll Swap (3)		552,000	$	(1.79	)
Q1 - Q4 2021	Crude Oil Basis Swap (1)		1,825,000	$	1.05
Q4 2020	Natural Gas		644,000	$	2.85
Q1 - Q4 2021	Natural Gas		4,380,000	$	2.76
Q4 2020	Natural Gas Basis Swap (4)		644,000	$	(1.07	)
Q1 - Q4 2021	Natural Gas Basis Swap (4)		4,380,000	$	(0.45	)


~~(1)~~ (1)	The basis differential price is between WTI Midland ~~Argus~~ Crude and the WTI NYMEX.


~~(2)~~ (2)	The basis differential price is between ~~LLS Argus Crude~~WTI Houston and the WTI NYMEX.

(3)

The swap is between WTI Roll and the WTI NYMEX.

~~(3)~~

(4)

The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.

Interest Rate Swaps

At times, the Company’s hedging activities include the use of interest rate swaps entered into in order to manage cash flow variability resulting from changes in interest rates. These derivative instruments are not accounted for under hedge accounting.

The Company had the following interest rate swaps as of September 30, 2020:

Effective Dates	Notional Amount		Fixed Rate
May 5, 2020 to May 5, 2022	$	125,000,000		0.286	%
May 5, 2022 to May 5, 2023	$	100,000,000		0.286	%
May 5, 2023 to May 7, 2024	$	75,000,000		0.286	%

Table of Contents

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the location and fair value amounts of all derivative instruments in the Condensed Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Condensed Consolidated Balance Sheets (in thousands):

September 30, 2019 December 31, 2018
Derivatives not
designated as hedging
contracts under ASC
Topic 815
Balance Sheet Location
Gross
Recognized
Assets /
Liabilities

Gross
Amounts
Offset

Net
Recognized
Assets /
Liabilities

Gross
Recognized
Assets /
Liabilities

Gross
Amounts
Offset

Net
Recognized
Assets /
Liabilities
Commodity contracts Derivative asset - current $ 27,014
$ (6,835 ) $ 20,179
$ 48,662
$ (4,774 ) $ 43,888
Commodity contracts Derivative liability - current $ 6,972
$ (6,835 ) $ 137
$ 5,302
$ (4,774 ) $ 528
Commodity contracts Derivative asset - noncurrent $ 10,650
$ (1,404 ) $ 9,246
$ 23,605
$ (2,484 ) $ 21,121
Commodity contracts Derivative liability - noncurrent $ 1,433
$ (1,404 ) $ 29
$ 4,375
$ (2,484 ) $ 1,891

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~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

		*September 30, 2020*							*December 31, 2019*
Derivatives not		*Gross*					*Net*		*Gross*					*Net*
designated as hedging	*Balance*	*Recognized*		*Gross*			*Recognized*		*Recognized*		*Gross*			*Recognized*
contracts under ASC	*Sheet*	*Assets /*		*Amounts*			*Assets /*		*Assets /*		*Amounts*			*Assets /*
Topic 815	*Location*	*Liabilities*		*Offset*			*Liabilities*		*Liabilities*		*Offset*			*Liabilities*
Commodity contracts	Derivative asset - current	$	26,773	$	(1,676	)	$	25,097	$	13,321	$	(4,461	)	$	8,860
Commodity contracts	Derivative liability - current	$	2,539	$	(1,676	)	$	863	$	11,350	$	(4,461	)	$	6,889
Interest rate swaps	Derivative liability - current	$	177	$	0		$	177	$	0	$	0		$	0
Commodity contracts	Derivative asset - noncurrent	$	4,727	$	0		$	4,727	$	1,031	$	(261	)	$	770
Commodity contracts	Derivative liability - noncurrent	$	355	$	0		$	355	$	261	$	(261	)	$	0
Interest rate swaps	Derivative liability - noncurrent	$	222	$	0		$	222	$	0	$	0		$	0

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Condensed Consolidated Statements of Operations and Condensed Consolidated Statements of Cash Flows (in thousands):

			*Three Months Ended*					*Nine Months Ended*
*Derivatives not designated as hedging contracts under ASC Topic 815*			*September 30,*					*September 30,*
	*Statement of Cash Flows Location*	*Statement of Operations Location*	*2020*			*2019*		*2020*		*2019*
Unrealized (loss) gain	Not separately presented	Not separately presented	$	(14,543	)	$	15,021	$	25,466	$	(33,332	)
Realized gain	Operating portion of net cash received in settlement of derivative contracts	Not separately presented		8,503			3,705		47,599		13,660
	Total (loss) gain on derivative contracts, net	(Loss) gain on derivative contracts, net	$	(6,040	)	$	18,726	$	73,065	$	(19,672	)

Included in Accounts receivable under the subheading of Joint interest billings and other in the Condensed Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019 are $3.6 million and $0.6 million, respectively, related to commodity hedge contracts settled as of that date for which the cash has not been received.

Derivatives not designated as hedging contracts under ASC Topic 815 Three Months Ended
September 30, Nine Months Ended
September 30,
Statement of Cash Flows Location Statement of Operations Location 2019 2018 2019 2018
Unrealized gain (loss) Not separately presented Not separately presented $ 15,021
$ (13,105 ) $ (33,332 ) $ (19,963 )
Realized gain (loss) Operating portion of net cash paid in settlement of derivative contracts Not separately presented 3,705
(4,376 ) 13,660
(13,643 )
Total gain (loss) on derivative contracts, net Gain (loss) on derivative contracts, net $ 18,726
$ (17,481 ) $ (19,672 ) $ (33,606 )

Note 4. Asset Impairments

The Company had the following non-cash asset impairment charges for the three and nine months ended September 30, 2020 (in thousands):

	*Three Months Ended September 30, 2020*		*Nine Months Ended September 30, 2020*
Proved property	$	0	$	25,252
Unproved property		2,115		19,676
Goodwill		0		17,620
Impairment expense	$	2,115	$	62,548

See further discussion of non-cash asset impairment charges to Proved property and Unproved property in Note 5. Oil and Natural Gas Properties and non-cash asset impairment charges to Goodwill in Note 15. Goodwill.

The Company did not record any impairments during the three and nine months ended September 30, 2019.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, costs to acquire oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale or retirement of oil and natural gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Gains and losses arising from the sale of properties are included in Income from operations in the Condensed Consolidated Statements of Operations.

The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. For the three and nine months ended September 30, 2020, depletion expense for oil and gas producing property and related equipment was $28.4 million and $75.7 million, respectively. For the three and nine months ended September 30, 2019, depletion expense for oil and gas producing property and related equipment was $13.9 million and $41.7 million, respectively. ~~For the three and nine months ended September 30, 2018, depletion expense for oil and gas producing property and related equipment was $12.7 million and $33.0 million, respectively.~~

Proved Properties

Proved oil and natural gas properties are reviewed for impairment on a nonrecurring basis. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.

Unproved Properties

Unproved properties consist of costs incurred to acquire undeveloped leases. Unproved oil and gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying a lease renewal fee, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful drilling on unproved leases are reclassified to proved properties.

The Company reviews its unproved properties periodically for impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, the Company’s geologists' evaluation of the property, and the remaining months in the lease term for the property.

Impairments to Oil and Natural Gas Properties

During the three ~~and nine~~ months ended ~~September 30, 2019,~~March 31, 2020, as a result of the recent decline in crude oil price futures, the Company ~~did not record any impairments~~recorded non-cash impairment charges of $25.3 million to its proved oil and natural

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~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

gas ~~properties. During the three~~properties and ~~nine months ended September 30, 2018, the Company recorded an impairment of $0.8~~$11.3 million to its unproved oil and natural gas properties, ~~as a result of acreage expirations in its properties~~ located in the Eagle Ford ~~Trend~~Trend. No such impairments were recorded in the three months ended September 30, 2020. As a result of ~~south Texas.~~certain acreage expirations, the Company recorded non-cash impairment charges of $2.1 million and $8.4 million to its unproved oil and natural gas properties during the three and nine months ended September 30, 2020, respectively.

The Company did not record any impairments to its oil and natural gas properties for the three and nine months ended September 30, 2019.

Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties as of September 30, 2020 and December 31, 2019, are summarized below (in thousands):

	*September 30,*			*December 31,*
	*2020*			*2019*
Oil and gas properties, successful efforts method:
Proved properties	$	1,096,318		$	1,046,208
Accumulated impairment to proved properties		(100,652	)		(75,400	)
Proved properties, net of accumulated impairments		995,666			970,808
Unproved properties		301,847			305,961
Accumulated impairment to Unproved properties		(65,365	)		(45,690	)
Unproved properties, net of accumulated impairments		236,482			260,271
Land		5,382			5,382
Total oil and gas properties, net of accumulated impairments		1,237,530			1,236,461
Accumulated depreciation, depletion and amortization		(271,012	)		(195,567	)
Net oil and gas properties	$	966,518		$	1,040,894

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5.6. Noncontrolling Interest

Earthstone consolidates the financial results of EEH and its subsidiaries and records a noncontrolling interest for the economic interest in Earthstone held by the members of EEH other than Earthstone and Lynden US. Net (loss) income attributable to noncontrolling interest in the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, ~~2019~~ 2020 and ~~2018~~2019 represents the portion of net (loss) income attributable to the economic interest in the Company held by the members of EEH other than Earthstone and Lynden US. Noncontrolling interest in the Condensed Consolidated Balance Sheets as of September 30, ~~2019~~2020 and December 31, ~~2018~~2019 represents the portion of net assets of the Company attributable to the members of EEH other than Earthstone and Lynden US.

The following table presents the changes in noncontrolling interest for the nine months ended September 30, ~~2019:~~2020:

	*EEH Units Held*											*Total EEH*
	*By Earthstone*					*EEH Units Held*						*Units*
	*and Lynden US*		%			*By Others*			%			*Outstanding*
As of December 31, 2019		29,421,131		45.5	%		35,260,680			54.5	%		64,681,811
EEH Units and Class B Common Stock converted to Class A Common Stock		251,309					(251,309	)					0
EEH Units issued in connection with the vesting of restricted stock units		538,309					0						538,309
As of September 30, 2020		30,210,749		46.3	%		35,009,371			53.7	%		65,220,120

EEH Units Held
By Earthstone
and Lynden US
%
EEH Units Held
By Others
%
Total EEH
Units
Outstanding
As of December 31, 2018 28,696,321
44.7 % 35,452,178
55.3 % 64,148,499
EEH Units and Class B Common Stock converted to Class A Common Stock 35,732
(35,732 ) —
EEH Units issued in connection with the vesting of restricted stock units 418,167
—
418,167
As of September 30, 2019 29,150,220
45.1 % 35,416,446
54.9 % 64,566,666

Note 6.7. Net (Loss) Income Per Common Share

Net (loss) income per common share—basic is calculated by dividing Net (loss) income by the weighted average number of shares of common stock outstanding during the period. Net (loss) income per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net (loss) income by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net (loss) income per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect.

A reconciliation of Net (loss) income per common share is as follows:

Three Months Ended
September 30, Nine Months Ended
September 30,
(In thousands, except per share amounts) 2019 2018 2019 2018
Net income attributable to Earthstone Energy, Inc. $ 11,770
$ 224
$ 3,343
$ 6,195

Net income per common share attributable to Earthstone Energy, Inc.:
Basic $ 0.41
$ 0.01
$ 0.12
$ 0.22
Diluted $ 0.41
$ 0.01
$ 0.12
$ 0.22

Weighted average common shares outstanding
Basic 29,032,842
28,257,376
28,883,907
28,011,298
Add potentially dilutive securities:
Unvested restricted stock units —
54,383
—
97,067
Unvested performance units —
—
—
—
Diluted weighted average common shares outstanding 29,032,842
28,311,759
28,883,907
28,108,365

~~Table~~

	*Three Months Ended*					*Nine Months Ended*
	*September 30,*					*September 30,*
(In thousands, except per share amounts)	*2020*			*2019*		*2020*			*2019*
Net (loss) income attributable to Earthstone Energy, Inc.	$	(5,445	)	$	11,770	$	(5,076	)	$	3,343

Net (loss) income per common share attributable to Earthstone Energy, Inc.:
Basic	$	(0.18	)	$	0.41	$	(0.17	)	$	0.12
Diluted	$	(0.18	)	$	0.41	$	(0.17	)	$	0.12

Weighted average common shares outstanding
Basic		30,073,635			29,032,842		29,810,705			28,883,907
Add potentially dilutive securities:
Unvested restricted stock units (1)		0			0		0			0
Unvested performance units (1)		0			0		0			0
Diluted weighted average common shares outstanding		30,073,635			29,032,842		29,810,705			28,883,907

(1) For the three and nine months ended September 30, 2020 and 2019, the Company had 0 dilutive effect related to unvested restricted stock units or performance units as, under the treasury stock method, the proceeds from the average unrecognized expense for both during these periods were in excess of ~~Contents~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

the weighted average outstanding fair value for the unvested shares for the same periods.

Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and net loss attributable to noncontrolling interest of $6.4 million for the three months ended September 30, 2020 and net loss attributable to noncontrolling interest of $6.0 million for the nine months ended September 30, 2020 would be added back to Net (loss) income attributable to Earthstone Energy, Inc. for the periods then ended, having no dilutive effect on Net (loss) income per common share attributable to Earthstone Energy, Inc.

Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and net income attributable to noncontrolling interest of $14.4 million for the three months ended September 30, 2019 and net income attributable to noncontrolling interest of $3.9 million for the nine months ended September 30, 2019 would be added back to Net (loss) income attributable to Earthstone Energy, Inc. for the periods then ended, having no dilutive effect on Net (loss) income per common share attributable to Earthstone Energy, Inc.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7.8. Common Stock

Class A Common Stock

At September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, there were ~~29,150,220~~30,210,749 and ~~28,696,321~~29,421,131 shares of Class A Common Stock issued and outstanding, respectively. During the three and nine months ended September 30, ~~2019,~~2020, as a result of the vesting and settlement of restricted stock units under the Earthstone Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the ~~"2014 Plan"~~“2014 Plan”), Earthstone issued 195,344 and 726,082 shares, respectively, of Class A Common Stock, of which 54,268 and 187,773 shares, respectively, of Class A Common Stock were retained as treasury stock and canceled to satisfy the related employee income tax liability. During the three and nine months ended September 30, 2019, as a result of the vesting and settlement of restricted stock units under the 2014 Plan, Earthstone issued 167,827 and 569,883 shares, respectively, of Class A Common Stock, of which 49,111 and 151,716 shares, respectively, of Class A Common Stock were retained as treasury stock and canceled to satisfy the related employee income tax liability. ~~During the three and nine months ended September 30, 2018,~~Additionally, as ~~a result of the vesting and settlement of restricted stock units under the 2014 Plan, Earthstone issued 115,574 and 569,585~~discussed below, shares ~~respectively, of Class A Common Stock, of which 30,511 and 142,937 shares, respectively,~~ of Class A Common Stock were ~~retained~~issued as ~~treasury stock and canceled to satisfy~~ the ~~related employee income tax liability.~~

result of conversions of Class B Common Stock.

Class B Common Stock

At September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, there were ~~35,416,446~~35,009,371 and ~~35,452,178~~35,260,680 shares of Class B Common Stock issued and outstanding, respectively. Each share of Class B Common Stock, together with ~~one~~1 EEH Unit, is convertible into ~~one~~1 share of Class A Common Stock. ~~No shares were converted during~~During the three and nine months ended September 30, ~~2019.~~2020, 49,316 and 251,309 shares, respectively, of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common Stock. During the three and nine months ended September 30, 2019, 35,732 shares of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common Stock. During the three and nine months ended September 30, 2018, 183,894 and 389,135 shares, respectively, of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common Stock.

Note 8.9. Stock-Based Compensation

Restricted Stock Units

The 2014 Plan, allows, among other things, for the grant of restricted stock units ~~("RSUs"~~(“RSUs”). As of September 30, ~~2019,~~2020, the maximum number of shares of Class A Common Stock that may be issued under the 2014 Plan was ~~6.4~~9.4 million shares.

Each RSU represents the contingent right to receive ~~one~~1 share of Class A Common Stock. The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting and settlement. The Company determines the fair value of granted RSUs based on the market price of the Class A Common Stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting and is net of forfeitures, as incurred. Stock-based compensation is included in General and administrative expense in the Condensed Consolidated Statements of Operations and is recorded with a corresponding increase in Additional paid-in capital within the Condensed Consolidated Balance Sheets.

The table below summarizes RSU award activity for the nine months ended September 30, ~~2019:~~

Shares Weighted-Average Grant Date Fair Value
Unvested RSUs at December 31, 2018 810,995
$ 8.83
Granted 762,350
$ 6.39
Forfeited (23,084 ) $ 7.64
Vested (569,883 ) $ 8.14
Unvested RSUs at September 30, 2019 980,378
$ 7.36

2020:

	*Shares*			*Weighted-Average Grant Date Fair Value*
Unvested RSUs at December 31, 2019		1,107,796		$	6.60
Granted		568,900		$	5.15
Forfeited		(1,083	)	$	5.19
Vested		(726,082	)	$	6.43
Unvested RSUs at September 30, 2020		949,531		$	5.86

As of September 30, ~~2019,~~2020, there was ~~$6.9~~$5.4 million of unrecognized compensation expense related to the RSU awards which will be recognized over a weighted average period of ~~0.94~~0.85 years.

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~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

For the three and nine months ended September 30, 2020, Stock-based compensation related to RSUs was $1.2 million and $4.2 million, respectively. For the three and nine months ended September 30, 2019, Stock-based compensation related to RSUs was $1.4 million and $4.5 million, respectively. ~~For the three and nine months ended September 30, 2018, Stock-based compensation related to RSUs was $1.2 million and $4.9 million, respectively.~~

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Performance Units

The table below summarizes performance unit (“PSU”) activity for the nine months ended September 30, ~~2019:~~

Shares Weighted-Average Grant Date Fair Value
Unvested PSUs at December 31, 2018 252,500
$ 13.75
Granted 669,550
$ 9.30
Unvested PSUs at September 30, 2019 922,050
$ 10.52

2020:

	*Shares*		*Weighted-Average Grant Date Fair Value*
Unvested PSUs at December 31, 2019		835,625	$	10.51
Granted		1,043,800	$	5.36
Unvested PSUs at September 30, 2020		1,879,425	$	7.65

On January ~~28, 2019,~~ 30, 2020, the Board of Directors of Earthstone (the ~~"Board"~~“Board”) granted ~~669,550~~1,043,800 PSUs (the “2020 PSUs”) to certain ~~executive~~ officers pursuant to the 2014 ~~Plan.~~ Plan (the “2020 Grant”). The2020 Grant was subject to the approval of an amendment to the 2014 Plan to increase the number of available shares available thereunder (the “2014 Plan Amendment”). The 2014 Plan Amendment was approved at the 2020 annual meeting of stockholders held on June 3, 2020. The 2020 PSUs are payable in shares of Class A Common Stock based upon the achievement by the Company over a period commencing on February 1, ~~2019~~ 2020 and ending on January 31, ~~2022 (the~~2023 (the “Performance Period”) of certain performance criteria established by the Board.

The ~~number~~2020 PSUs are eligible to be earned based on the annualized Total Shareholder Return (“TSR”) of the Class A Common Stock during a three-year period beginning on February 1, 2020. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:

Earthstone’s Annualized TSR		*TSR Multiplier*
23.9% or greater		2.0
14.5%		1.0
8.4%		0.5
Less than 8.4%		0.0

In the event that greater than 1.0x of the 2020 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common ~~Stock~~Stock. Based on the COVID-19 pandemic and the recent commodity price crash, the Company believes that ~~may be issued~~the target annualized TSR of 14.5% included in the 2020 PSU awards will be ~~determined by multiplying the number of PSUs granted by the Relative Total Shareholder Return ("TSR") Percentage (0%~~difficult to ~~200%). The “Relative TSR Percentage” is the percentage, if any, achieved by attainment of a certain predetermined range of targets for the Performance Period.~~

TSR for the Company and each of the peer companies is generally determined by dividing (A) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the last calendar day of the Performance Period minus the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the Performance Period plus cash dividends paid over the Performance Period by (B) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the Performance Period.

achieve.

The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2020PSUs, ~~granted on January 28, 2019,~~ assuming a risk-free rate of ~~2.6%~~1.4% and ~~volatilities ranging from 40.1% to 114.1%~~volatility of 62.0%, the Company calculated the weighted average grant date fair value per PSU to be ~~$9.30.~~

$5.36.

As of September 30, ~~2019,~~2020, there was ~~$6.5~~$7.3 million of unrecognized compensation expense related to the PSU awards which will be amortized over a weighted average period of ~~1.09~~0.98 years.

For the three and nine months ended September 30, 2020, Stock-based compensation related to the PSUs was approximately $1.2 million and $3.5 million, respectively. For the three and nine months ended September 30, 2019, Stock-based compensation related to the PSUs was approximately $0.8 million and $2.2 million, respectively. ~~For the three and nine months ended September 30, 2018, Stock-based compensation related to the PSUs was approximately $0.3 million and $0.7 million, respectively.~~

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 9.10. Long-Term Debt

Credit ~~Agreement~~

~~In May, 2017,~~ Facility

On November 21, 2019, Earthstone, ~~Energy Holdings, LLC (“EEH” or the~~EEH (the “Borrower”), Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (“Wells Fargo”), Royal Bank of Canada, as Syndication Agent, BOKF, NA dba Bank of Texas (“BOKF”) as Issuing Bank with respect to Existing Letters of Credit, SunTrust Bank, as Documentation Agent, and the lenders party thereto (the “Lenders”) entered into a ~~subsidiary~~credit agreement (the “Credit Facility”), which replaced the Prior Credit Facility (as defined below), which was terminated on November 21, 2019.

Concurrently with the effectiveness of ~~Earthstone, each~~the Credit Facility, the Company terminated that certain credit agreement, dated as ofMay 9, 2017 (the “Prior Credit Facility”), by and among the Borrower, Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden USA Operating, LLC, Bold Energy III LLC ~~("Bold"~~(“Bold”), Bold Operating, LLC, asthe guarantors ~~(the “Guarantors”), BOKF, NA dba Bank Of Texas, as Agent and Lead Arranger, Wells Fargo Bank, National Association, as Syndication Agent, and~~party thereto, the lenders party thereto, ~~(the “Lenders”), entered into~~and BOKF, as administrative agent.

On March 27, 2020, in connection with a ~~credit agreement (as amended, modified or restated from time to time,~~redetermination of the ~~“EEH Credit Agreement”).~~

~~The~~ borrowing base under the Credit Facility, the borrowing base was set at $275 million, representing a 15% decrease from the previous borrowing base of $325 million.

On September 28, 2020, Earthstone, EEH, Wells Fargo, the guarantors party thereto, and the Lenders entered into an amendment (the “Amendment”) to the Credit ~~Agreement~~Facility. Among other things, the Amendment decreased the borrowing base from $275 million to $240 million, increased the interest rate on outstanding borrowings by 25 to 50 basis points, increased the flexibility to finance and make acquisitions, and added certain restrictions related to dividends and distributions.

The next regularly scheduled redetermination of the borrowing base is ~~subject to redetermination~~on or around April 1, 2021. Subsequent redeterminations will occur on or about each November 1st and May 1st ~~and November 1st of each year.~~ thereafter. The amounts borrowed under the ~~EEH~~ Credit ~~Agreement~~Facility bear annual interest rates at either (a) the ~~London Interbank Offered~~adjusted LIBO Rate ~~(“LIBOR”~~(as customarily defined) (the “Adjusted LIBO Rate”) plus ~~1.75%~~2.00% to ~~2.75%~~3.25% or (b) the sum of (i) the greatest of (A) the prime ~~lending~~ rate of ~~Bank~~Wells Fargo, (B) the federal funds rate plus ½ of ~~Texas~~1.0%, and (C) the Adjusted LIBO Rate for an interest rate period of one month plus ~~0.75%~~1.0%, (ii) plus 1.00% to ~~1.75%~~2.25%, depending on the ~~amounts~~amount borrowed under the ~~EEH~~ Credit ~~Agreement.~~Facility. Principal amounts outstanding under the ~~EEH~~ Credit ~~Agreement~~Facility are due and payable in full at maturity on ~~May 9, 2022.~~ November 21, 2024. All of the obligations under the ~~EEH~~ Credit ~~Agreement,~~Facility, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the ~~EEH~~ Credit ~~Agreement~~Facility include

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~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

paying a commitment fee of 0.375% orto 0.50%, per year, depending on ~~borrowing base utilization, per year~~the amount borrowed under the Credit Facility, to the Lenders in respect of the unutilized commitments ~~thereunder, as well as~~thereunder. EEH is also required to pay customary letter of credit fees.

Effective May 2020, the Company entered into certain ~~other customary fees.~~

interest rate swaps, exchanging the LIBO Rate for a fixed rate of 0.286% (the “Swap”). The ~~EEH~~initial notional amount of the Swap is $125 million through May 2022 and decreases to $100 million through May 2023 and $75 million through May 2024.

The Credit ~~Agreement~~Facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, ~~enter into sale and leaseback transactions,~~ pay dividends and ~~make~~ distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.

In addition, the ~~EEH~~ Credit ~~Agreement~~Facility requires EEH to maintain the following financial covenants: a current ratio ~~as defined by the EEH Credit Agreement,~~ of not less than 1.0 to 1.0 and a consolidated leverage ratio of not greater than 4.0 to 1.0. ~~Leverage~~ Consolidated leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter ~~(excluding any debt from obligations relating to non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives)~~ to (ii) ~~the product of~~ EBITDAX for the applicable period, which was calculated as EBITDAX for the four consecutive fiscal quarters ending on such ~~fiscal quarter multiplied by four.~~date. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) ~~non-cash losses under FASB ASC 815 as a result of changes in~~certain distributions to employees related to the ~~fair market value of derivatives,~~stock compensation, (vii) ~~exploration~~certain transaction related expenses, (viii) ~~impairment~~reimbursed indemnification expenses related to certain dispositions and investments, (ix) non-cash ~~compensation~~extraordinary, usual, or nonrecurring expenses or losses, (x) other non-cash charges and minus (b) to the extent included in consolidated net income in such period: (i) non-cash income, (ii) gains on asset dispositions, disposals and abandonments outside of the ordinary course of business and (iii) to the extent not otherwise deducted from consolidated net income, the aggregate amount of any pass-through cash distributions received by Borrower during such period ~~non-cash gains under FASB ASC 815 as a result~~in an amount equal to the aggregate amount of ~~changes in the fair market value of derivatives.~~

pass-through cash distributions actually made by Borrower during such period.

The ~~EEH~~ Credit ~~Agreement~~Facility contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default and ~~if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor.~~a change in control. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of September 30, ~~2019,~~2020, EEH was in compliance with the covenants under the ~~EEH~~ Credit ~~Agreement.~~

~~On May 1, 2019, the borrowing base under the EEH Credit Agreement was increased from $275.0 million to $325.0 million.~~ Facility.

As of September 30, ~~2019, $125.0~~2020, $130.0 million of borrowings were outstanding, bearing annual interest of ~~4.044%~~2.658%, resulting in an additional ~~$200.0~~$110.0 million of borrowing base availability under the ~~EEH~~ Credit ~~Agreement.~~Facility. At December 31, ~~2018,~~2019, there were ~~$78.8~~$170.0 million of borrowings outstanding under the ~~EEH~~ Credit ~~Agreement.~~

Facility.

For the nine months ended September 30, ~~2019,~~2020, under the Credit Facility, the Company had borrowings of ~~$165.3~~$93.9 million and ~~$119.1~~$133.9 million in repayments of borrowings.

For the three and nine months ended September 30, 2020, interest on borrowings under the Credit Facility averaged 2.48% and 2.89% per annum, respectively, which excluded commitment fees of $0.2 million and $0.5 million, respectively, and amortization of deferred financing costs of $0.1 million and $0.2 million, respectively. For the three and nine months ended September 30, 2019, interest on borrowings under the Credit Facility averaged 4.38% and 4.53% per annum, respectively, which excluded commitment fees of $0.2 million and $0.5 million, respectively, and amortization of deferred financing costs of $0.1 million and $0.3 million, respectively. For the three and nine months ended September 30, 2018, interest on borrowings averaged 3.94% and 3.91% per annum, respectively, which excluded commitment fees of $0.1 million and $0.6 million, respectively, and amortization of deferred financing costs of $0.1 million and $0.2 million, respectively.

During the three and nine months ended September 30, 2019, $0.04 million and $0.2 million, respectively, of costs associated with the EEH Credit Agreement were capitalized. During the three and nine months ended September 30, 2018, the Company capitalized $0.1 million and $0.3 million, respectively, of costs associated with the EEH Credit Agreement. These capitalized costs are included in Other noncurrent assets in the Condensed Consolidated Balance Sheets.

The Company’s policy is to capitalize the financing costs associated with its debt and amortize those costs on a straight-line basis over the term of the associated debt. These capitalized costs are included in Other noncurrent assets in the Condensed Consolidated Balance Sheets. NaN costs associated with the Credit Facility were capitalized during the three and nine months ended September 30, 2020 nor 2019.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note ~~10.~~11. Asset Retirement Obligations

The Company has asset retirement obligations associated with the future plugging and abandonment of oil and gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.

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~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

The following table summarizes the Company’s asset retirement obligation transactions recorded during the nine months ended September 30,(in thousands):

	*2020*
Beginning asset retirement obligations	$	2,164
Liabilities incurred		46
Accretion expense		137
Divestitures		(10	)
Revision of estimates		(2	)
Ending asset retirement obligations	$	2,335

2019
Beginning asset retirement obligations $ 2,229
Liabilities incurred 43
Liabilities settled (179 )
Accretion expense 160
Ending asset retirement obligations $ 2,253

Note ~~11.~~12. Related Party Transactions

FASB ASC Topic 850, Related Party Disclosures, requires that information about transactions with related parties that would make a difference in decision making shall be disclosed so that users of the financial statements can evaluate their significance.

Flatonia Energy, LLC (“Flatonia”), which owns approximately 10.1% of the outstanding Class A Common Stock and approximately 4.6% of the combined voting power of the Company's outstanding Class A and Class B Common Stock as of September 30, 2019, is a party to a joint operating agreement (the “Operating Agreement”) with the Company. The Operating Agreement covers certain jointly owned oil and natural gas properties located in the Eagle Ford Trend in Texas. In connection with the Operating Agreement, the Company made payments to Flatonia of $3.8 million and $12.1 million and received payments from Flatonia of $2.0 million and $4.9 million for the three and nine months ended September 30, 2019, respectively. For the three and nine months ended September 30, 2018, the Company made payments to Flatonia of $0.0 million and $12.4 million and received payments from Flatonia of $0.7 million and $4.8 million, respectively. At September 30, 2019 and December 31, 2018, amounts receivable from Flatonia in connection with the Operating Agreement were $0.3 million and $0.8 million, respectively. Payables related to revenues outstanding and due to Flatonia as of September 30, 2019 and December 31, 2018 were $1.1 million and $1.6 million, respectively.

Earthstone's majority shareholder consists of various investment funds managed by a ~~venture capital~~private equity firm who may manage other investments in entities with which the Company interacts in the normal course of business. On ~~October 31, 2019,~~ February 12, 2020, the Company sold certain of its interests in oil and natural gas leases and wells ~~located in Martin County, Texas~~ in an arm’s length transaction to a portfolio company of Earthstone’s majority shareholder (not under common control) for cash consideration of approximately ~~$3.6~~$0.4 million.

In connection with the Olenik v. Lodzinski et al. lawsuit described below in Note ~~12.~~13. Commitments and Contingencies, Earthstone’s majority shareholder was also named in the lawsuit. As a result of the Settlement Agreement (defined below), the Company has concluded negotiations with its insurance carrier regarding an allocation of defense costs and settlement contributions above its deductible for all the parties named in the lawsuit. In June 2020, the Company received $0.6 million in preliminary reimbursements from its majority shareholder and as of September 30, 2020 recorded a receivable in the amount of $0.6 million from its majority shareholder based on estimated additional defense costs to finalize the settlement and the respective allocated portion of the settlement payments.

Note 13. Commitments and Contingencies

Legal

From time to time, ~~the Company~~Earthstone and its subsidiaries may be involved in various legal proceedings and claims in the ordinary course of business.

Olenik v. ~~Lodzinksi~~Lodzinski et al.: On June 2, 2017, Nicholas Olenik filed a purported shareholder class and derivative action in the Delaware Court of Chancery against Earthstone’s Chief Executive Officer, along with other members of the Board, EnCap Investments L.P. ~~("EnCap"~~(“EnCap”), Bold, Bold ~~Energy~~ Holdings ~~LLC ("Bold Holdings")~~ and Oak Valley Resources, LLC. The complaint alleges that Earthstone’s directors breached their fiduciary duties in connection with the contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 ~~(the "Bold~~(the “Bold Contribution ~~Agreement"~~Agreement”), by and among Earthstone, EEH, Lynden US, Lynden USA Operating, LLC, Bold Holdings and Bold. The Plaintiff asserts that the directors negotiated the business combination pursuant to the Bold ~~Transaction~~Contribution Agreement (the “Bold Transaction”) to benefit EnCap and its affiliates, failed to obtain adequate consideration for the Earthstone shareholders who were not affiliated with EnCap or Earthstone management, did not follow an adequate process in negotiating and approving the Bold Transaction and made materially misleading or incomplete proxy disclosures in connection with the Bold Transaction. The suit seeks unspecified damages and purports to assert claims derivatively on behalf of Earthstone and as a class action on behalf of all persons who held ~~Common Stock~~common stock up to March 13, 2017, excluding defendants and their affiliates. On July 20, 2018, the Delaware Court of Chancery granted the ~~defendants'~~defendants’ motion to dismiss and entered an order dismissing the action in its entirety with prejudice. The Plaintiff filed an appeal with the Delaware Supreme Court. On ~~February 6, 2019, the Delaware Supreme Court heard oral arguments from the Plaintiff and Defendants' counsel. On~~ April 5, 2019, the Delaware Supreme Court affirmed the Delaware Court of Chancery’s dismissal of the proxy disclosure claims but reversed the Delaware Court of Chancery’s dismissal of the other claims, holding that the allegations with respect to those claims were sufficient for pleading purposes. ~~Earthstone~~After engaging in extensive pre-trial discovery, the parties engaged in a mediation process that resulted in a non-binding settlement term sheet on September 21, 2020. The term sheet is being translated into a Stipulation and ~~each~~Agreement of Compromise, Settlement and Release Agreement (the “Settlement Agreement”) between the parties and will then be filed with the Delaware Court of Chancery for approval. The principal terms of the ~~other~~anticipated Settlement Agreement are as follows: (i) a $3.5 million all-in cash settlement payment (the “Fund”) to be funded by defendants ~~believe~~and/or their insurers into an escrow account, (ii) a bi-lateral complete and full release of all claims against defendants and plaintiffs, and (iii) that 55% of the ~~claims are entirely without merit and intend to mount a vigorous defense. The ultimate outcome of this suit is uncertain,~~

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~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~and while Earthstone is confident in its position, any potential monetary recovery or loss~~Fund (the derivative payment) be paid to Earthstone to be used as determined by management, according to their fiduciary duties and business judgment, 45% of the Fund (the class payment) be paid to members of the class or current stockholders of Earthstone. The Company expects court approval of the Settlement Agreement and in addition estimates the insurance carriers and related affiliates to reimburse the Company in the amount of $2.8 million and $0.1 million, respectively. As described above, the Company expects to receive a portion of the derivative payment, however, the amount cannot be ~~estimated~~reasonably determined at this time.

Prior to September 30, 2020, due to uncertainty of reimbursement, the Company recorded and accrued litigation costs when incurred and recorded insurance reimbursements as an offset only when proceeds were received in Transactions costs. In light of the Settlement Agreement, insurance carrier agreement on allocation of defense costs and settlement payment combined with the history of reimbursements from insurance carriers and related affiliate, a high probability of reimbursement exists. Accordingly, the Company has accrued $3.75 million related to the Settlement Agreement and estimated final defense costs associated with this legal action included in Accrued expenses in the Condensed Consolidated Balance Sheets, offset by an accrued $5.7 million of estimated reimbursements from insurance carriers and the majority shareholder which are included in Accounts receivable: Joint interest billings and other, net in the Condensed Consolidated Balance Sheets, with the impact of both items included in Transaction costs in the Condensed Consolidated Statements of Operations.

Environmental and Regulatory

As of September 30, ~~2019,~~2020, there were no known environmental or other regulatory matters related to the Company’s operations that are reasonably expected to result in a material liability to the Company.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note ~~13.~~14. Income Taxes

The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return which include Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the non-controlling interest. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.

During the nine months ended September 30, ~~2019,~~2020, the Company recorded income tax expense of approximately ~~$0.7~~$0.1 million which included ~~(1)~~(1) no income tax expense for Lynden US ~~of $0.1 million~~ as a result of its share of the distributable income from EEH, ~~(2)~~(2) a deferred income tax ~~expense~~benefit for Earthstone of ~~$0.6~~$0.8 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset which was previously recorded as future realization of the net deferred tax asset cannot be assured and ~~(3)~~(3) deferred income tax expense of $0.1 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the nine months ended September 30, 2020.

During the nine months ended September 30, 2019, the Company recorded income tax expense of approximately $0.7 million which included (1) income tax benefit for Lynden US of $0.1 million as a result of its share of the distributable loss from EEH, (2) no net income tax benefit for Earthstone as the $0.6 million income tax benefit resulting from its share of the distributable loss from EEH had a full valuation allowance recorded against it as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $0.6 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the nine months ended September 30, 2019.

Note 15. Goodwill

Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets. The fair value of Goodwill is classified as a Level 3 measurement according to the fair value hierarchy defined by ASC 820. Goodwill is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. If the results of such tests are such that the fair value of the reporting unit is less than the carrying value, goodwill is then reduced by an amount that is equal to the amount by which the carrying value exceeds the fair value.

A discounted future cash flow analysis of the properties to which the Goodwill was associated was performed based on commodity price futures as of March 31, 2020. The resulting fair value was lower than the net book value of the associated properties. Additionally, the Company’s enterprise value, calculated as the combined market capitalization of the Company’s equity and long-term debt, was lower than the book value of its assets, without allocating between the Company's two major properties, Midland properties and Eagle Ford properties. Accordingly, the entire $17.6 million balance of Goodwill was impaired on that date. No additional impairments have been recorded to Goodwill through September 30,2020. The Company did not have any non-cash impairment charges to Goodwill for the three and nine months ended September 30, 2019.

~~During the nine months ended~~

Accumulated impairments to Goodwill as of September 30, ~~2018, the Company recorded income tax expense of approximately $0.1~~2020 and December 31, 2019 were $36.7 million ~~which included (1) income tax expense for Lynden US of $0.3~~and $19.1 million, as a result of its share of the distributable income from EEH, offset by a $0.5 million discrete income tax benefit related to refundable AMT tax credits resulting from the Tax Cuts and Jobs Act ("TCJA"), (2) income tax expense for Earthstone of $1.1 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset which was previously recorded as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $0.3 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the nine months ended September 30, 2018.respectively.

~~Note 14. Leases~~

Our operating lease activities consist of leases for office space. Our finance lease activities consist of leases for vehicles. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms generally ranging from one to three years. The exercise of lease renewal options is at our sole discretion. Certain leases also include options to purchase the leased property. The depreciable life of assets and leasehold improvements is limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. None of our lease agreements include variable lease payments. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. See discussion of the January 1, 2019 implementation impact at ~~Note 1. Basis of Presentation and Summary of Significant Accounting Policies~~.

~~Supplemental balance sheet information as of September 30, 2019 for our leases is as follows~~ ~~(in thousands)~~:

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~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

Leases Balance Sheet Location
Assets
Noncurrent:
Operating Operating lease right-of-use assets $ 3,295
Finance Office and other equipment, net of accumulated depreciation and amortization 630
Total lease assets $ 3,925

Liabilities
Current:
Operating Operating lease liabilities $ 586
Finance Finance lease liabilities 256
Noncurrent:
Operating Operating lease liabilities 2,722
Finance Finance lease liabilities 111
Total lease liabilities $ 3,675

*The difference between assets and liabilities includes a $0.1 million adjustment to NCI and a $0.07 million adjustment to accumulated deficit, both at the beginning of the period as part of the ASC 842 implementation adjustment.

Our operating lease expenses for the three and nine months ended September 30, 2019 were $0.2 million and $0.6 million, respectively, and are included in General and administrative expense in our Condensed Consolidated Statements of Operations. Our finance lease expenses for the three and nine months ended September 30, 2019 were $0.1 million and $0.3 million, respectively, and are included in depreciation, depletion and amortization expense and interest expense, net in our Condensed Consolidated Statements of Operations. Additionally, we capitalized as part of oil and gas properties $2.6 million and $6.7 million of short-term lease costs related to drilling rig contracts during the three and nine months ended September 30, 2019. All of our drilling rig contracts have enforceable terms of less than one year.

~~Minimum contractual obligations for our leases (undiscounted) as of September 30, 2019 are as follows~~ ~~(in thousands)~~:

Operating Finance
2019 (excluding nine months ended September 30, 2019) $ 207
$ 81
2020 632
219
2021 791
84
2022 696
5
2023 596
—
Thereafter 757
—
Total lease payments $ 3,679
$ 389
Less imputed interest (371 ) (22 )
Total lease liability $ 3,308
$ 367

Cash payments for our operating leases were $0.2 million and $0.6 million, respectively, for the three and nine months ended September 30, 2019. Cash payments for our finance leases were $0.1 million and $0.4 million, respectively, for the three and nine months ended September 30, 2019. For the three and nine months ended September 30, 2019 there were $2.6 million and $3.2 million of right-of-use assets obtained in exchange for lease obligations for our operating leases. The amounts related to our finance leases were not material to our consolidated financial statements.

As of September 30, 2019, the weighted average remaining lease terms of our operating and finance leases were 2.2 years and 1.6 years, respectively. The weighted average discount rates used to determine the lease liabilities as of September 30, 2019 for our operating and finance leases were 4.35% and 6.69%, respectively. The discount rate used for operating leases is based on the Company's incremental borrowing rate. The discount rate used for finance leases is based on the rates implicit in the leases.

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

Statement Regarding Forward-Looking Information

This discussion and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to numerous risks, uncertainties and assumptions. Certain of these risks are summarized ~~in this report and~~ under “Item 1A. Risk Factors” in our ~~2018~~2019 Annual Report on Form 10-K and “Part II, Item 1A - Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 that ~~was~~were filed with the Securities and Exchange Commission (“SEC”), which you should read carefully in connection with our forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

You should read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in conjunction with the corresponding sections and our audited consolidated financial statements for the year ended December 31, ~~2018,~~2019, which are included in our ~~2018~~2019 Annual Report on Form 10-K.

Overview

Earthstone Energy, Inc., a Delaware corporation ~~("Earthstone"~~(“Earthstone” and together with our consolidated subsidiaries, the ~~"Company," "our," "we," "us,"~~“Company,” “our,” “we,” “us,” or similar terms), is a growth-oriented independent oil and gas company engaged in the acquisition and development of oil and gas reserves through activities that include the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions and mergers. Our operations are all in the upstream segment of the oil and natural gas industry and all our properties are onshore in the United States. At present, our ~~primary~~ assets are located in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas.

Our primary focus is concentrated in the Midland Basin of west Texas where our acreage has multiple stacked pay intervals in the Wolfcamp and, to a lesser extent, the Spraberry formations. We believe the Midland Basin area is characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons and high drilling success rates.

~~Management’s Plans~~

COVID-19

According to the United States (“U.S.”) Centers for Disease Control and Prevention (the “CDC”), in March 2020, the U.S. entered the acceleration (or 4th) phase of the pandemic of the novel coronavirus (“COVID-19”). On May 1, 2020 they indicated that there was still the potential for future acceleration. This conclusion was based on the Pandemic Intervals Framework created by the CDC, which describes the progression of an influenza pandemic in six intervals or phases. The duration of each phase may vary depending on the type of virus and the public health response.

The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of financial and commodity markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been a significant reduction in demand for and prices of oil and natural gas, which has adversely affected our business. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including how the pandemic and measures taken in response to it impact demand for oil and natural gas, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. There is uncertainty around the extent and duration of disruption, including any resurgence, and we expect that the longer the period of such disruption continues, the greater the adverse impact will be on our business. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the U.S. and world economies, the U.S. capital markets and market conditions, and how quickly and to what extent normal economic and operating conditions can resume.

Operational Status

As a producer of oil, natural gas and NGLs, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. We have continued to operate as permitted under these regulations while taking mitigation efforts and steps to protect the health and safety of our employees. The safety of our employees is paramount, and we have emphasized the respective guidelines to support our mitigation efforts. Our ~~plans include a continued~~field personnel are performing their job responsibilities and practicing mitigation guidelines with no issues to date. Our non-field personnel had been working remotely, using information technology in which we previously invested. More recently, the majority of our non-field personal have been working at our corporate offices while adhering to County and CDC guidelines. Upon returning to work at our corporate offices, we implemented protocols that consist of required mask wearing zones, installed sanitization equipment in various locations and practice social distancing in gathering areas such as conference rooms. We have managed and conducted both field and non-field functions effectively thus far, including our day to day operations, our accounting and financial reporting systems and our internal control over financial reporting. We will continue to focus on the ~~Midland Basin through the development~~health and safety of our ~~properties~~employees in conformity with the respective jurisdictional mitigation guidelines.

Commodity Market Challenges

The significant decline in commodity prices resulting from the COVID-19 pandemic has negatively impacted producers of oil, natural gas and NGLs in the U.S. and elsewhere. The COVID-19 pandemic resulted in global consumer demand contraction and the ensuing supply/demand imbalance is in turn having a disruptive impact on oil and gas exploration and production. In April 2020, WTI crude oil prices averaged $16.55/Bbl and briefly fell below $0/Bbl, closing at -$36.98/Bbl on April 20, 2020. In response, management began to voluntarily shut-in as much production as was feasible in an effort to preserve reserves to sell in the future. As prices returned to acceptable levels, management returned those wells to production as quickly as possible, beginning in late May and early June. Management estimates that total net production was curtailed by approximately 60% in May, with minimal volumes curtailed in April and June. Since early June, WTI crude oil prices have averaged over $40/Bbl and we have been operating at full production capacity.

While crude prices have recovered from recent lows, further ~~expansion~~recovery in demand and reductions in global oil inventories will be required to return oil prices to pre-pandemic and economic slowdown levels. Within the U.S., the combination of producer activity reduction and production curtailments was sufficient to reduce domestic supply below demand and prevent material infrastructure operational curtailments from occurring. However, with curtailed U.S. volumes returning, we may choose to curtail some or all of our ~~acreage footprint~~estimated production due to future changes in supply and demand fundamentals.

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Operational/Financial Challenges

It is difficult to model and predict how our operations and financial status may change as ~~an operator. Our development~~a result of COVID-19. There is a range of possible outcomes, depending upon how quickly both economic activity and the demand for oil recovers which is a function of how quickly solutions are developed to overcome the effects of COVID-19. In our industry, any forecast, plans and changes to operations and financial status are a function of commodity prices. Assuming that oil prices stay depressed or worsen, we believe we can continue to operate and produce our properties at a minimum in a cash flow neutral position for the next 12 months. We will have to manage the possibility of well shut-ins, both voluntary and involuntary, to preserve our assets and cash flows. A significant driver in the future may be the financial institutions’ view on commodity prices with respect to borrowing base redeterminations. Since the beginning of 2020, our borrowing base has been reduced from $325 million to $240 million. Further significant reductions in the borrowing base under our Credit Facility could create a borrowing base deficiency which may lead to a default. We believe global, as well as national, mitigation efforts currently being implemented to fight COVID-19 have had, and may continue to have, a material impact on commodity prices and may continue to present significant challenges to our industry.

The ongoing effects of COVID-19, including a substantial decrease in economic activity, have contributed to equity market volatility and resulted in a global recession. Similar to other producers in our business, we experienced volatility and a decline in the price of our Class A common stock. While the price of our Class A common stock has recently stabilized somewhat, it remains historically low.

Liquidity

In March 2020, in response to the significant decrease in commodity prices, we significantly reduced our capital program for ~~2019 presently includes~~2020 and halted all drilling ~~approximately 19.0 gross/14.7 net operated wells~~ and ~~completing 17.0 gross/12.6 net~~completion activity. In light of ~~these operated wells. In addition,~~recent oil price recoveries and meaningful service cost reductions compared to earlier in the year, we have ~~assumed participating~~commenced completions of a six-well pad and currently expect total capital spending for 2020 to be in ~~drilling 20.0 gross/5.0 net wells~~the range of $65 - $70 million. Additionally, we currently expect to begin completions of a five-well pad in January 2021. We expect to fund these completions with internally generated cash flows.

COVID-19 has adversely impacted our revenues in the three and ~~completing 5.0 gross/2.0 net wells where we have~~nine months ended September 30, 2020 as a ~~non-operated working interest. At~~result of both low commodity prices and our ~~Eagle Ford Trend properties,~~voluntary shut-ins. However, due to our ~~development program includes drilling 10.0 gross/5.1 net operated wells and completing~~commodity hedging activities partially offsetting those reduced revenues, there has been no significant overall impact on our cash flows from producing activities.

Since the beginning of 2020, our borrowing base has been reduced through two sequential reductions from $325 million to $240 million. We continue remain in compliance with all ~~of these operated wells. In order to achieve these plans, we have an approved annual budget of $205.0 million. Commodity~~covenants under our Credit Facility. If commodity prices continue to be ~~volatile~~depressed, we may experience future borrowing base reductions.

For further discussion of our liquidity as of September 30, 2020, see Liquidity and Capital Resources below.

Oil and Gas Reserves

In line with our borrowing base reductions, our oil and gas reserves have significantly been reduced primarily due to the significant decrease in commodity prices from year end. Further deterioration of commodity prices would further negatively impact our oil and gas reserves.

Impairments

The COVID-19 effects resulted in impairments in the first quarter on our proved developed properties and undeveloped properties in the amount of $25.3 million and $11.3 million, respectively. Further reductions in our oil and gas reserves and commodity prices may result in additional impairments on our oil and gas properties. Including impairments for certain acreage expirations, impairments on our proved developed properties and undeveloped properties for the nine months ended September 30, 2020 were $25.3 million and $19.7 million, respectively.

Government Assistance

Although management explored all assistance available under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), the Company was not eligible for any of the programs therein with the exception of the deferral of employment tax deposits and payments which management has currently not elected to pursue.

Impact on Capital Program

In light of the current economic environment, we ~~intend~~have reduced our 2020 capital program in order to ~~be vigilant to adjust our business plans accordingly.~~

~~In addition to our~~preserve capital development program for 2019, our plans also include an acreage expansion program that includes looking for opportunities where we can trade acreage with other operators or bolt on acreage through acquisitions.and cash flows. Our ~~intent~~short-term strategy is to ~~increase~~weather COVID-19 and be in a position, when the time comes, to execute our ~~overall operated locations and allow us~~long-term business strategy to develop our properties efficiently, as well as being able to take advantage of growth opportunities as they arise. However, an extended period of severely depressed commodity prices and low demand may create more uncertainty in our ability to model and make plans to participate in any economic recovery.

Employee Reduction Measures

In June 2020, management completed a workforce reduction effort that reduced the number of full-time employees from 68 to 60 by month end, resulting in over a 10% decrease in aggregate salaries and wages going forward. Severance related costs associated with these reduction measures resulted in operating expenses of $0.4 million in June 2020. At this time, management has no future plans for further workforce reductions; however, if adverse industry conditions persist, further employee reduction measures may be necessary.

Outlook

We do not expect commodity prices to return to pre-pandemic levels in the short term. In the longer term, we believe the U.S. and world economies will recover and the demand for oil will return in the range of pre-COVID-19 levels as more developments occur in meeting and addressing COVID-19 business challenges. Our current financial focus is to maintain the health of our balance sheet and continue limited capital expenditures with our internally generated cash flows to enable us to be in a position to execute a business strategy as commodity prices return to pre-pandemic levels.

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Recent Developments

Borrowing Base Redetermination

On September 28, 2020, Earthstone, EEH (the “Borrower”), Wells Fargo Bank, National Association as Administrative Agent (“Wells Fargo”), the guarantors party thereto, and the lenders party thereto (the “Lenders”) entered into an amendment (the “Amendment”) to the Credit Agreement dated November 21, 2019, by and among EEH, as Borrower, Earthstone, as Parent, Wells Fargo as Administrative Agent and Issuing Bank, BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, and the Lenders (together with all amendments or other modifications, the “Credit Facility”). Among other things, the Amendment decreased the borrowing base from $275 million to $240 million, increased the interest rate on outstanding borrowings by 25 to 50 basis points, increased the flexibility to finance and make acquisitions, and added certain restrictions related to dividends and distributions.

As of September 30, 2020, we had outstanding borrowings under our Credit Facility of $130 million, which represents a reduction of 24% compared to the $170 million in outstanding borrowings as of December 31, 2019. Our only debt is borrowings under our Credit Facility.

Consolidation Focus

We believe that the current industry environment will move to more consolidations; however, execution may be hampered by producers with high debt levels and sellers unwilling to acknowledge persistent low commodity prices. We continue to pursue value-accretive and scale-enhancing consolidation opportunities, as we believe we are in a position to operate effectively despite the COVID-19 induced low oil price. We are focusing our attention on acquisition and corporate merger opportunities that would increase the scale of our operations. In addition, we believe the current industry environment presents unique opportunities with distressed assets or corporations that will be distressed in the near future which would provide us the potential for further consolidation because of our financial strength. At the same time, we will seek to block up acreage ~~with long~~that would allow for longer horizontal laterals ~~(7,500~~that would provide for higher economic returns when commodity prices recover and we return to ~~12,000+ foot lateral lengths)~~asset development. In short, we believe we are well qualified to be a consolidator which could increase the scale of our operations and add value to our shareholders.

Officer Appointments

Effective April 1, 2020, our former Chairman and Chief Executive Officer, Mr. Frank A. Lodzinski, was appointed Executive Chairman and our former President, Mr. Robert J. Anderson, was appointed President and Chief Executive Officer.

Interest Rate Swap

Effective May 1, 2020, we entered into an interest rate swap, exchanging the LIBO Rate for a fixed rate of 0.286% (the “Swap”). ~~We will also remain active in seeking M&A transactions in this high economic return geographic area.~~

The initial notional amount of the Swap is $125 million through May 2022 and decreases to $100 million through May 2023 and $75 million through May 2024.

Areas of Operation

Our primary focus is concentrated in the Midland Basin of west Texas, a high oil and liquids rich resource which provides us with multiple horizontal targets with proven production results, long-lived reserves and historically high drilling success rates.

~~Midland Basin~~

As previously disclosed, we completed 21 gross wells (8.0 gross/6.3 net operated and 13.0 gross/2.8 net non-operated) and spud an additional 30 gross wells (12.0 gross/12.0 net operated and 18.0 gross/4.5 net non-operated) through the first three ~~quarters of 2019. We currently expect to complete approximately 9.0 gross/6.4 net operated~~ wells in ~~the fourth quarter of 2019. We intend~~southeast Reagan County in late March and brought them online in April, prior to ~~continue to initiate completion activities when we accumulate an adequate inventory of wells for efficient operations.~~

~~In July 2019, we entered into a Wellbore Development Agreement ("WDA") with a non-affiliated industry partner. This WDA will reduce our working interest in certain~~voluntarily shutting the wells in ~~Reagan County. The industry partner is obligated to pay a promoted (proportionately higher) share~~for the duration of the ~~capital expenditures on an initial eight wells, with an option~~month of May. In May, approximately 60% of our total production was shut-in. As oil prices have improved since then, we have returned to ~~participate, on the same basis,~~full production capacity. We have experienced no adverse effects from this short-term curtailment and have incurred no significant costs in ~~up to 11 additional wells, to earn 35% of the working interest in these wells. Earned working interest is in the wellbore only~~restoring production.

In late May, we concluded our 2020 drilling program and ~~the industry partner does not earn rights to any of the acreage or adjacent targets.~~

~~Commencing in early 2018, market concerns regarding future take-away capacity adversely affected oil and gas price differentials~~released our contracted rig operating in the Midland Basin. ~~Although oil and gas pipelines have recently been placed into service~~During the first half of the year, we drilled a total of five wells in ~~the area,~~our Hamman Upton project along with ~~additional pipelines expected to be placed into service~~six wells in ~~the future, there are still future take-away capacity constraints. While we believe the economic returns from~~ our operations are attractive at current price levels and our wells are meeting or exceeding our type curves, our cash flows have been negatively impacted by oil and gas price differentials (excluding the impact of derivatives). Increasing or sustained negative oil and gas price differentials would adversely affect our future cash flows and could cause us to reduce the pace of development of our properties.

~~Eagle Ford Trend~~

~~In our operated leasehold acreage~~Ratliff unit, all located in Upton County, Texas. We have commenced completions of the ~~Eagle Ford Trend, we spud 10.0 gross/5.1 net wells~~six-well pad in ~~the first three quarters of 2019~~our Ratliff unit and expect to ~~have them all completed by~~begin completions of the ~~end of 2019.~~

five-well Hamman Upton pad in January 2021.

Despite the disruption in the oil markets resulting from the COVID-19 pandemic, we continue to seek acreage trade and acquisition opportunities in the Midland Basin which would allow for longer laterals, increased operated inventory and greater operating efficiency.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires us to use our judgment to make estimates and assumptions that affect certain amounts reported in our financial statements. As additional information becomes available, these estimates and assumptions are subject to change and thus impact amounts reported in the future. Critical accounting policies are those accounting policies that involve judgment and uncertainties affecting the application of those policies and the likelihood that materially different amounts would be reported under different conditions or using differing assumptions. We periodically update our estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. ~~Other than the adoption of ASC Topic 842 described in~~ ~~Note 1. Basis of Presentation and Summary of Significant Accounting Policies, there~~There have been no significant changes to our critical accounting policies during the nine months ended September 30, ~~2019.~~2020.

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Results of Operations

Three Months Ended September 30, ~~2019,~~2020, compared to the Three Months Ended September 30, ~~2018~~

Three Months Ended September 30,
2019 2018 Change
Sales volumes:
Oil (MBbl) 646
645
— %
Natural gas (MMcf) 1,248
947
32 %
Natural gas liquids (MBbl) 267
188
42 %
Barrels of oil equivalent (MBOE) 1,121
991
13 %
Average Daily Production (Boepd) 12,181
10,766
13 %

Average prices:
Oil (per Bbl) $ 54.89
$ 60.12
(9 )%
Natural gas (per Mcf) $ 0.72
$ 1.89
(62 )%
Natural gas liquids (per Bbl) $ 10.71
$ 29.31
(63 )%

Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl) $ 59.43
$ 53.30
12 %
Natural gas ($/Mcf) $ 1.34
$ 1.92
(30 )%
Natural gas liquids ($/Bbl) $ 10.71
$ 29.31
(63 )%

(In thousands)
Oil revenues $ 35,443
38,791
(9 )%
Natural gas revenues $ 903
1,790
(50 )%
Natural gas liquids revenues $ 2,858
5,495
(48 )%

Lease operating expense $ 7,259
$ 4,843
50 %
Severance taxes $ 1,858
$ 2,254
(18 )%
Impairment expense $ —
$ 833
NM
Depreciation, depletion and amortization $ 14,079
$ 12,842
10 %

General and administrative expense (excluding stock-based compensation)
$ 4,023
$ 3,422
18 %
Stock-based compensation $ 2,207
$ 1,522
45 %
General and administrative expense $ 6,230
$ 4,944
26 %

Transaction costs $ 42
$ 892
NM
(Loss) gain on sale of oil and gas properties $ (120 ) 4,096
NM
Interest expense, net $ (1,609 ) $ (565 ) 185 %

Unrealized gain (loss) on derivative contracts $ 15,021
$ (13,105 ) NM
Realized gain (loss) on derivative contracts $ 3,705
$ (4,376 ) NM
Gain (loss) on derivative contracts, net $ 18,726
$ (17,481 ) NM

Litigation settlement $ —
$ (4,775 ) NM
Income tax expense $ (575 ) $ (172 ) NM

2019

	Three Months Ended
	September 30,
	2020			2019			Change
Sales volumes:
Oil (MBbl)		839			646			30	%
Natural gas (MMcf)		2,010			1,248			61	%
Natural gas liquids (MBbl)		386			267			45	%
Barrels of oil equivalent (MBOE)		1,560			1,121			39	%
Average Daily Production (Boepd)		16,959			12,181			39	%

Average prices:
Oil (per Bbl)	$	39.50		$	54.89			(28	)%
Natural gas (per Mcf)	$	1.31		$	0.72			82	%
Natural gas liquids (per Bbl)	$	13.60		$	10.71			27	%

Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl)(1)	$	49.34		$	59.43			(17	)%
Natural gas ($/Mcf)	$	1.45		$	1.34			8	%
Natural gas liquids ($/Bbl)	$	13.60		$	10.71			27	%

(In thousands)
Oil revenues	$	33,158		$	35,443			(6	)%
Natural gas revenues	$	2,642		$	903			193	%
Natural gas liquids revenues	$	5,247		$	2,858			84	%

Lease operating expense	$	7,044		$	6,419			10	%
Production and ad valorem taxes	$	2,696		$	2,698			(0	)%
Impairment expense	$	2,115		$	—			NM
Depreciation, depletion and amortization	$	28,538		$	14,079			103	%

General and administrative expense (excluding stock-based compensation)	$	3,393		$	3,850			(12	)%
Stock-based compensation	$	2,403		$	2,207			9	%
General and administrative expense	$	5,796		$	6,057			(4	)%

Transaction costs	$	(705	)	$	215			NM
Interest expense, net	$	(1,186	)	$	(1,609	)		(26	)%

Unrealized (loss) gain on derivative contracts	$	(14,543	)	$	15,021			NM
Realized gain on derivative contracts	$	8,503		$	3,705			NM
(Loss) gain on derivative contracts, net	$	(6,040	)	$	18,726			NM

Income tax expense	$	(130	)	$	(575	)		NM

NM – Not Meaningful

Oil revenues

For the three months ended September 30, ~~2019,~~2020, oil revenues decreased by ~~$3.3~~$2.3 million or 9%6% relative to the comparable period in ~~2018, primarily~~2019. Of the decrease, $9.9 million was due to a decrease in our realized ~~price.~~price, partially offset by $7.6 million attributable to an increase in volume. Our average realized price per Bbl decreased from ~~$60.12~~$54.89 for the three months ended September 30, ~~2018~~2019 to ~~$54.89~~$39.50 or 9%28% for the three months ended September 30, ~~2019.~~

2020. We had a net increase in the volume of oil sold of 194 MBbls or 30%, primarily due to new wells brought online in 2020.

Natural gas revenues

For the three months ended September 30, ~~2019,~~2020, natural gas revenues ~~decreased~~increased by ~~$0.9~~$1.7 million or ~~50%~~193% relative to the comparable period in ~~2018, primarily~~2019. Of the increase, $1.0 million was attributable to increased sales volume and $0.7 million was due to ~~a drastic decrease~~an increase in realized price in the Midland Basin. Our average realized price per Mcf decreased 62% from $1.89 for the three months ended September 30, 2018 to $0.72 for the three months ended September 30, 2019. Approximately 97% of our natural gas sales volumes for the period was from the Midland Basin, which, since the fourth quarter of 2018, has been experiencing a lack of sufficient pipeline transportation that is connected to markets which are purchasing the gas. This has resulted in negative gas prices at times, whereby the seller is actually paying the purchaser to take the gas.price. The total volume of natural gas produced and sold increased ~~301~~by 762 MMcf or ~~32%~~61% primarily due to new wells brought online ~~partially offset by~~in 2020. In the ~~impact~~prior year's quarter, lack of ~~divestitures~~sufficient pipeline transportation resulted in low natural gas prices, which have improved in the ~~latter half~~current year's quarter. Our average realized price per Mcf increased 82% from $0.72 for the three months ended September 30, 2019 to $1.31 for the three months ended September 30, 2020.

Table of ~~2018.~~Contents

Natural gas liquids revenues

For the three months ended September 30, ~~2019,~~2020, natural gas liquids revenues ~~decreased~~increased by ~~$2.6~~$2.4 million or ~~48%~~84% relative to the comparable period in ~~2018.~~2019. Of the ~~decrease, $3.5~~increase, $1.6 million was due to increased volume and $0.8 million was attributable to ~~a decrease~~an increase in our realized price, partially offset by an increase of $0.9 million due to increased volume. Approximately 95% of our natural gas liquids sales volumes for the period was from the Midland Basin. Since the fourth quarter of 2018, the price for fractionated natural gas liquids has steadily decreased, and after also taking into account the cost to transport our natural gas liquids, has resulted in significant decreases in prices received.price. The volume of natural gas liquids produced and sold increased by 79119 MBbls or ~~42%~~45%, primarily due to new wells brought online in 2020. Our average realized price per Bbl increased 27% from $10.71 for the three months ended September 30, 2019 to $13.60 for the three months ended September 30, 2020.

Lease operating expense (“LOE”)

LOE increased by $0.6 million or 10% for the three months ended September 30, 2020 relative to the comparable period in 2019, primarily due to new wells brought online, partially offset by ~~the impact of divestitures in the latter half of 2018.~~

~~Lease operating expense (“LOE”)~~

LOE increased by $2.4 million or 50% for the three months ended September 30, 2019 relative to the comparable period in 2018, primarily due to additional producing wells brought online, which drove a 13% increase in production volume; in addition to a $1.1 million increase driven by a greater number oflower workover ~~projects~~project costs compared to the prior year ~~quarter.~~

~~Severance~~period.

Production and ad valorem taxes

~~Severance~~

Production and ad valorem taxes for the three months ended September 30, ~~2019 decreased $0.4 million or 18%~~2020 were flat as compared to the ~~comparable~~prior year period ~~in 2018, primarily due to~~as the impact of decreased oil prices ~~of oil and natural gas liquids.~~was offset by increased production. As a percentage of revenues from oil, natural gas, and natural gas liquids, ~~severance~~production taxes remained flat as compared to the prior ~~year period.~~

year.

Impairment expense

~~As a~~

During the three months ended September 30, 2020, we recorded non-cash impairments totaling $2.1 million to unproved oil and natural gas properties as the result of certain acreage ~~expirations related to our Eagle Ford Trend properties, we~~expirations. No such impairments were recorded ~~non-cash asset impairments of $0.8 million~~during the three months ended September 30, 2019.

Depreciation, depletion and amortization (“DD&A”)

DD&A for the three months ended September 30, ~~2018.~~

~~Depreciation, depletion and amortization (“DD&A”)~~

~~DD&A~~2020 increased ~~for the three months ended September 30, 2019~~ by ~~$1.2~~$14.5 million, or ~~10%~~103% relative to the comparable period in ~~2018,~~2019. The increase was primarily ~~due~~related to development and acquisition activity, partially offset by a first quarter 2020 impairment charge of $25.3 million, that resulted in increased costs subject to ~~depletion~~depletion. Other factors contributing to the increase were higher sales volumes and ~~an increase in production primarily in the Midland Basin.~~

certain downward adjustments to estimated recoverable proved oil and natural gas reserves caused by lower commodity prices.

General and administrative expense (“G&A”)

G&A for the three months ended September 30, ~~2019 increased~~2020 decreased by ~~$1.3~~$0.3 million, or ~~26%~~4% relative to the comparable period in ~~2018~~2019, primarily due to ~~employee costs~~lower cash-based incentive compensation expenses, including the impact of workforce reduction efforts in light of the ~~current year resulting from a larger average headcount, as well as~~drastic decline in commodity prices, partially offset by non-cash stock-based compensation expense related to ~~the performance-based restricted stock units awarded to our executive officers on~~awards granted in January ~~28, 2019, partially offset by lower legal~~2020, employee severance costs and ~~professional fees.~~

increased director and officer insurance premium costs.

Transaction costs

For the three months ended September 30, ~~2019, we incurred nominal~~2020, transaction costs ~~as compared~~decreased by $0.9 million primarily due to expected final defense costs and reimbursements from our major shareholder and insurance carrier associated with the anticipated settlement of litigation related to the ~~three months ended September 30, 2018, where transaction costs consisted of $0.9 million of legal~~Bold Transaction that closed on May 9, 2017. See Note 13. Commitments and ~~consulting fees associated with a contribution agreement executed on October 17, 2018. This contribution agreement was terminated~~Contingencies in ~~December 2018.~~

the Notes to Unaudited Condensed Consolidated Financial Statements.

Interest expense, net

Interest expense ~~increased~~decreased from ~~$0.6 million for the three months ended September 30, 2018 to~~ $1.6 million for the three months ended September 30, 2019 to $1.2 million for the three months ended September 30, 2020, primarily due to ~~higher average~~lower effective interest rates on borrowings outstanding compared to the prior year period. See Note 9.10. Long-Term Debt in the Notes to Unaudited Condensed Consolidated Financial Statements.

~~Gain (loss)~~

(Loss) gain on derivative contracts, net

For the three months ended September 30, 2020, we recorded a net loss on derivative contracts of $6.0 million, consisting of unrealized mark-to-market losses of $14.6 million related to our commodity hedges and unrealized gains of $0.1 million related to our interest rate swap, partially offset by net realized gains on settlements of our commodity hedges of $8.5 million. For the three months ended September 30, 2019, we recorded a net gain on derivative contracts of $18.7 million, consisting of unrealized mark-to-market gains of $15.0 million related to our commodity hedges and net realized gains on settlements of our commodity hedges of $3.7 million.

Income tax expense

For the three months ended September 30, ~~2018,~~2020, we recorded an income tax expense of approximately $0.1 million which included (1) no income tax expense for Lynden US as a result of its share of the distributable income from EEH, (2) deferred income tax benefit for Earthstone of $0.9 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset which was previously recorded as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $0.1 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, ~~on derivative contracts of $17.5 million, consisting of unrealized mark-to-market losses of $13.1 million and net realized losses on settlements of $4.4 million.~~

~~Litigation Settlement~~

~~During~~or related income tax expense or benefit, for the three months ended September 30, ~~2018, we recorded an expense of $4.8 million related to the expected settlement of certain litigation.~~

~~Income tax expense~~

2020.

During the three months ended September 30, 2019, we recorded income tax expense of approximately $0.6 million which included (1) income tax expense for Lynden US of $0.6 million as a result of its share of the distributable income from EEH and (2) deferred income tax expense for Earthstone of $2.2 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset which was previously recorded as future realization of the net deferred tax asset cannot be assured.

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~~During~~

Nine Months Ended September 30, 2020, compared to the ~~three~~Nine Months Ended September 30, 2019

	Nine Months Ended
	September 30,
	2020			2019			Change
Sales volumes:
Oil (MBbl)		2,520			2,027			24	%
Natural gas (MMcf)		5,031			3,318			52	%
Natural gas liquids (MBbl)		870			705			23	%
Barrels of oil equivalent (MBOE)		4,229			3,285			29	%
Average Daily Production (Boepd)		15,433			12,033			28	%

Average prices:
Oil (per Bbl)	$	36.92		$	55.08			(33	)%
Natural gas (per Mcf)	$	0.96		$	0.64			50	%
Natural gas liquids (per Bbl)	$	11.46		$	15.17			(24	)%

Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl)(1)	$	55.14		$	60.42			(9	)%
Natural gas ($/Mcf)(1)	$	1.31		$	1.49			(12	)%
Natural gas liquids ($/Bbl)	$	11.46		$	15.17			(24	)%

(In thousands)
Oil revenues	$	93,017		$	111,657			(17	)%
Natural gas revenues	$	4,855		$	2,126			128	%
Natural gas liquids revenues	$	9,976		$	10,691			(7	)%

Lease operating expense	$	21,971		$	20,485			7	%
Production and ad valorem taxes	$	7,198		$	8,001			(10	)%
Rig termination expense	$	426		$	—			NM
Impairment expense	$	62,548		$	—			NM
Depreciation, depletion and amortization	$	76,096		$	42,281			80	%

General and administrative expense (excluding stock-based compensation)	$	11,950		$	13,268			(10	)%
Stock-based compensation	$	7,665		$	6,680			15	%
General and administrative expense	$	19,615		$	19,948			(2	)%

Transaction costs	$	(324	)	$	797			NM
Interest expense, net	$	(4,207	)	$	(4,735	)		(11	)%

Unrealized gain (loss) on derivative contracts	$	25,466		$	(33,332	)		NM
Realized gain on derivative contracts	$	47,599		$	13,660			NM
Gain (loss) on derivative contracts, net	$	73,065		$	(19,672	)		NM

Income tax expense	$	(112	)	$	(728	)		NM

(1) Includes $5.7 million and $2.1 million of cash proceeds related to hedges unwound during the second quarter of 2020 and first quarter of 2019, respectively.

NM – Not Meaningful

Oil revenues

For the nine months ended September 30, ~~2018,~~2020, oil revenues decreased by $18.6 million or 17% relative to the comparable period in 2019. Of the decrease, $36.8 million was attributable to a decrease in our realized price, partially offset by $18.2 million attributable to an increase in volume. Our average realized price per Bbl decreased from $55.08 for the nine months ended September 30, 2019 to $36.92 or 33% for the nine months ended September 30, 2020. We had a net increase in the volume of oil sold of 492 MBbls or 24%, primarily due to new wells brought online offset by voluntary production shut-ins in May 2020.

Natural gas revenues

For the nine months ended September 30, 2020, natural gas revenues increased by $2.7 million or 128% relative to the comparable period in 2019. Of the increase, $1.6 million was due to increased sales volume and $1.1 million was attributable to an increase in realized price. Our average realized price per Mcf increased 50% from $0.64 for the nine months ended September 30, 2019 to $0.96 for the nine months ended September 30, 2020. In the prior year's period, lack of sufficient pipeline transportation resulted in low natural gas prices, which have improved in the current year period. The total volume of natural gas produced and sold increased 1,713 MMcf or 52% primarily due to new wells brought online offset by voluntary production shut-ins in May 2020.

Natural gas liquids revenues

For the nine months ended September 30, 2020, natural gas liquids revenues decreased by $0.7 million or 7% relative to the comparable period in 2019. Of the decrease, $2.6 million was attributable to a decrease in our realized price, partially offset by $1.9 million attributable to increased volume. The volume of natural gas liquids produced and sold increased by 166 MBbls or 23%, primarily due to new wells brought online offset by voluntary production shut-ins in May 2020.

Table of Contents

Lease operating expense (“LOE”)

LOE increased by $1.5 million or 7% for the nine months ended September 30, 2020 relative to the comparable period in 2019, primarily due to additional producing wells brought online, which drove a 29% increase in production volume, offset by voluntary production shut-ins in May 2020, as well as a decrease in workover project costs as compared to the prior year period.

Production and ad valorem taxes

Production and ad valorem taxes for the nine months ended September 30, 2020 decreased by $0.8 million or 10% relative to the comparable period in 2019, as the impact of increased volume was more than offset by the impact of decreased commodity prices. As a percentage of revenues from oil, natural gas, and natural gas liquids, production taxes declined slightly as compared to the prior year primarily due to lower realized commodity prices.

Rig termination expenses

During the nine months ended September 30, 2020, we concluded our 2020 drilling program and released our contracted drilling rig operating in the Midland Basin, recording rig termination expense of $0.4 million.

Impairment expense

During the nine months ended September 30, 2020, we recorded non-cash impairments totaling $62.5 million, which consisted of $25.3 million to proved oil and natural gas properties, $19.7 million to unproved oil and natural gas properties and $17.6 million to goodwill. No such impairments were recorded during the nine months ended September 30, 2019.

Depreciation, depletion and amortization (“DD&A”)

DD&A for the nine months ended September 30, 2020 increased by $33.8 million, or 80% relative to the comparable period in 2019. The increase was primarily related to development and acquisition activity, partially offset by a first quarter 2020 impairment charge of $25.3 million, that resulted in increased costs subject to depletion. Other factors contributing to the increase were higher sales volumes and certain downward adjustments to estimated recoverable proved oil and natural gas reserves caused by lower commodity prices.

General and administrative expense (“G&A”)

G&A for the nine months ended September 30, 2020 decreased by $0.3 million, or 2% relative to the comparable period in 2019, as a reduction in cash-based compensation expenses was almost entirely offset by non-cash stock-based compensation expense related to awards granted in January 2020, employee severance costs and increased director and officer insurance premium costs.

Transaction costs

For the nine months ended September 30, 2020, transaction costs decreased by $1.1 million primarily due to expected final defense costs and reimbursements from our major shareholder and insurance carrier associated with the anticipated settlement of litigation related to the Bold Transaction that closed on May 9, 2017. See Note 13. Commitments and Contingencies in the Notes to Unaudited Condensed Consolidated Financial Statements.

Interest expense, net

Interest expense decreased from $4.7 million for the nine months ended September 30, 2019 to $4.2 million for the nine months ended September 30, 2020, primarily due to lower effective interest rates on borrowings outstanding compared to the prior year period. See Note 10. Long-Term Debt in the Notes to Unaudited Condensed Consolidated Financial Statements.

Gain (loss) on derivative contracts, net

For the nine months ended September 30, 2020, we recorded a net gain on derivative contracts of $73.1 million, consisting of unrealized mark-to-market gains of $25.9 million related to our commodity hedges, unrealized mark-to-market losses of $0.4 million related to our interest rate swap and net realized gains on settlements of our commodity hedges of $47.6 million. For the nine months ended September 30, 2019, we recorded a net loss on derivative contracts of $19.7 million, consisting of unrealized mark-to-market losses of $33.3 million related to our commodity hedges, partially offset by net realized gains on settlements of our commodity hedges of $13.7 million.

Income tax expense

For the nine months ended September 30, 2020, we recorded an income tax expense of approximately ~~$0.2~~$0.1 million which included (1) no income tax expense for Lynden US ~~of $0.1 million~~ as a result of its share of the distributable income from EEH, (2) a deferred income tax ~~expense~~benefit for Earthstone of ~~$0.2~~$0.8 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset which was previously recorded as future realization of the net deferred tax asset cannot be assured and (3) a deferred income tax expense of $0.1 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the ~~three months ended September 30, 2018.~~

~~Nine Months Ended September 30, 2019, compared to the Nine Months Ended September 30, 2018~~

Nine Months Ended September 30,
2019 2018 Change
Sales volumes:
Oil (MBbl) 2,027
1,696
20 %
Natural gas (MMcf) 3,318
2,883
15 %
Natural gas liquids (MBbl) 705
489
44 %
Barrels of oil equivalent (MBOE) 3,285
2,665
23 %
Average Daily Production (Boepd) 12,033
9,762
23 %

Average prices:
Oil (per Bbl) $ 55.08
$ 61.97
(11 )%
Natural gas (per Mcf) $ 0.64
$ 2.17
(71 )%
Natural gas liquids (per Bbl) $ 15.17
$ 26.10
(42 )%

Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl)⁽¹⁾
$ 60.42
$ 53.82
12 %
Natural gas ($/Mcf)⁽¹⁾
$ 1.49
$ 2.23
(33 )%
Natural gas liquids ($/Bbl) $ 15.17
$ 26.10
(42 )%

(In thousands)
Oil revenues $ 111,657
$ 105,111
6 %
Natural gas revenues $ 2,126
$ 6,257
(66 )%
Natural gas liquids revenues $ 10,691
$ 12,753
(16 )%

Lease operating expense $ 22,531
$ 14,509
55 %
Severance taxes $ 5,955
$ 6,115
(3 )%
Impairment expense $ —
$ 833
NM
Depreciation, depletion and amortization $ 42,281
$ 33,362
27 %

General and administrative expense (excluding stock-based compensation)
$ 13,848
$ 13,274
4 %
Stock-based compensation $ 6,680
$ 5,535
21 %
General and administrative expense $ 20,528
$ 18,809
9 %

Transaction costs $ 217
$ 892
NM
(Loss) gain on sale of oil and gas properties $ (446 ) $ 4,608
(110 )%
Interest expense, net $ (4,735 ) $ (1,788 ) 165 %

Unrealized loss on derivative contracts $ (33,332 ) $ (19,963 ) NM
Realized gain (loss) on derivative contracts $ 13,660
$ (13,643 ) NM
Loss on derivative contracts, net $ (19,672 ) $ (33,606 ) NM

Litigation settlement $ —
$ (4,775 ) NM
Income tax expense $ (728 ) $ (119 ) NM

~~(1) Includes $2.1 million of cash proceeds related to hedges unwound during the first quarter of 2019.~~

~~NM – Not Meaningful~~

~~Oil revenues~~

~~For the~~ nine months ended September 30, 2019, oil revenues increased by $6.5 million or 6% relative to the comparable period in 2018. Of the increase, $18.2 million was attributable to an increase in volume, partially offset by $11.7 million attributable to a decrease in our realized price. Our average realized price per Bbl decreased from $61.97 for the nine months ended September 30, 2018 to $55.08 or 11% for the nine months ended September 30, 2019. We had a net increase in the volume of oil sold of 331 MBbls or 20%, primarily due to new wells brought online, partially offset by the impact of divestitures in the latter half of 2018.

~~Natural gas revenues~~

For the nine months ended September 30, 2019, natural gas revenues decreased by $4.1 million or 66% relative to the comparable period in 2018 primarily due to a drastic decline in realized price in the Midland Basin. Our average realized price per Mcf decreased 71% from $2.17 for the nine months ended September 30, 2018 to $0.64 for the nine months ended September 30, 2019. Approximately 96% of our natural gas sales volumes for the period was from the Midland Basin, which, since the fourth quarter of 2018, has been experiencing a lack of sufficient pipeline transportation that is connected to markets which are purchasing the gas. This has resulted in negative gas prices at times, whereby the seller is actually paying the purchaser to take the gas. The total volume of natural gas produced and sold increased 435 MMcf or 15% primarily due to new wells brought online, partially offset by the impact of 2018 gas well divestitures.

~~Natural gas liquids revenues~~

For the nine months ended September 30, 2019, natural gas liquids revenues decreased by $2.1 million or 16% relative to the comparable period in 2018. Of the decrease, $5.4 million was attributable to a decrease in our realized price, partially offset by $3.3 million attributable to increased volume. Approximately 94% of our natural gas liquids sales volumes for the period was from the Midland Basin. Since the fourth quarter of 2018, the price for fractionated natural gas liquids has steadily decreased, and after also taking into account the cost to transport our natural gas liquids, has resulted in significant decreases in prices received. The volume of natural gas liquids produced and sold increased by 216 MBbls or 44%, primarily due to new wells brought online, partially offset by the impact of divestitures in the latter half of 2018.

~~Lease operating expense (“LOE”)~~

LOE increased by $8.0 million or 55% for the nine months ended September 30, 2019 relative to the comparable period in 2018, primarily due to additional producing wells brought online, which drove a 23% increase in production volume, in addition to a $3.5 million increase driven by a greater number of workover projects as compared to the prior year period.

~~Severance taxes~~

Severance taxes for the nine months ended September 30, 2019 decreased $0.2 million or 3% relative to the comparable period in 2018, as the impact of increased volume was largely offset by the impact of decreased prices of oil and natural gas liquids. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained flat when compared to the prior year period.

~~Impairment expense~~

During the nine months ended September 30, 2018, we recorded non-cash asset impairments of $0.8 million to our unproved oil and natural gas properties resulting from certain acreage expirations related to our Eagle Ford Trend properties.

~~Depreciation, depletion and amortization (“DD&A”)~~

DD&A increased for the nine months ended September 30, 2019 by $8.9 million, or 27% relative to the comparable period in 2018, primarily due to development and acquisition activity that resulted in increased costs subject to depletion and an increase in production primarily in the Midland Basin.

~~General and administrative expense (“G&A”)~~

G&A for the nine months ended September 30, 2019 increased by $1.7 million, or 9% relative to the comparable period in 2018, primarily due to employee costs in the current year resulting from a larger average headcount, as well as non-cash stock-based compensation expense related to the performance-based restricted stock units awarded to our executive officers on January 28, 2019, partially offset by lower legal and professional fees.

~~Transaction costs~~

For the nine months ended September 30, 2019, we incurred nominal transaction costs as compared to the nine months ended September 30, 2018, where transaction costs consisted of $0.9 million of legal and consulting fees associated with a contribution agreement executed on October 17, 2018. This contribution agreement was terminated in December 2018.

~~Interest expense, net~~

Interest expense increased from $1.8 million for the nine months ended September 30, 2018 to $4.7 million for the nine months ended September 30, 2019, primarily due to higher average borrowings outstanding compared to the prior year period. ~~See Note 9. Long-Term Debt~~ ~~in the Notes to Unaudited Condensed Consolidated Financial Statements.~~

~~Loss on derivative contracts, net~~

For the nine months ended September 30, 2019, we recorded a net loss on derivative contracts of $19.7 million, consisting of unrealized mark-to-market losses of $33.3 million, partially offset by net realized gains on settlements of $13.7 million. For the nine months ended September 30, 2018, we recorded a net loss on derivative contracts of $33.6 million, consisting of unrealized mark-to-market losses of $20.0 million and net realized losses on settlements of $13.6 million.

~~Litigation Settlement~~

~~During the nine months ended September 30, 2018, we recorded an expense of $4.8 million related to the expected settlement of certain litigation.~~

~~Income tax expense~~

2020.

During the nine months ended September 30, 2019, we recorded income tax expense of approximately $0.7 million which included (1) income tax expense for Lynden US of $0.1 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $0.6 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset which was previously recorded as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $0.6 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the nine months ended September 30, 2019.

Table of Contents

Liquidity and Capital Resources

Our primary needs for capital are for working capital obligations with respect to operating our properties and for the development of our oil and natural gas assets. At September 30, 2020, we had approximately $5.3 million in cash and approximately $110.0 million in unused borrowing capacity under our Credit Facility (discussed below) for a total of approximately $115.3 million in funds available for operational and capital funding.

We have no material long-term contracts, relatively low leverage, and a strong hedge position, which affords us the flexibility to adjust our capital plan. In March 2020, we took action to significantly reduce our capital program for 2020 and made a decision to halt all drilling and completion activity. In light of recent oil price recoveries and meaningful service cost reductions compared to earlier in the year, we have commenced completions of a six-well pad and currently expect total capital spending for 2020 to be in the range of $65 - $70 million. Additionally, we currently expect to begin completions of a five-well pad in January 2021. We expect to fund this completion activity with internally generated funds.

COVID-19 has adversely impacted our revenues for the nine months ended September 30, 2020 as a result of both low commodity prices and voluntary shut-ins of our production. However, due to our commodity hedging activities offsetting those reduced revenues, there has been no significant overall impact on our cash flows.

Since the beginning of 2020, our borrowing base has been reduced from $325 million to $240 million. Despite two sequential reductions in our borrowing base, we remain in compliance with all covenants under our Credit Facility. During the nine months ended September 30, 2018, we recorded income tax expense of approximately $0.1 million which included (1) income tax expense for Lynden US of $0.3 million as a result of its share of the distributable income from EEH, offset by a $0.5 million discrete income tax benefit related to refundable AMT tax credits resulting from the TCJA, (2) income tax expense for Earthstone of $1.1 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset which was previously recorded as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $0.3 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the nine months ended September 30, 2018.

~~Liquidity and Capital Resources~~

The oil and gas industry is capital intensive, requiring continued development of undeveloped acreage. We have significant undeveloped acreage and future drilling locations in the Midland Basin, generally consisting of 7,500 to 12,000-foot lateral lengths. At September 30, 2019, we had approximately $9.8 million in cash and approximately $200 million in unused borrowing capacity under the EEH Credit Agreement (discussed below) available for operational and capital funding. We currently estimate 2019 capital expenditures will be approximately $205.0 million, of which2020, we have ~~incurred $152.4 million~~reduced our outstanding bank debt by $40 million. Based on ~~an accrual basis through September 30, 2019. Our 2019~~our production profile, cost structure, minimal capital program ~~assumes a 19-well program for our operated acreage~~and the hedge positions we have in the Midland Basin and a 10-well program for our operated Eagle Ford acreage as well as estimated expenditures for our non-operated Midland Basin properties and land and infrastructure activities. We likely will continueplace, we expect to ~~outspend our~~generate adequate cash flows provided by operating activities ~~over~~to fund the completion activity for the six wells in progress and reduce debt, although not at ~~least~~ the ~~next 12 months from~~same levels as in the ~~date~~third quarter, for the remainder of ~~this report based on current assumptions. However,~~2020. As a result, we believe we will have sufficient liquidity with cash flows from operations and borrowings under ~~the EEH~~our Credit ~~Agreement~~Facility to meet our cash requirements for the next 12 ~~months in order to meet our cash requirements. We may consider various financial arrangements or other transactions, including but not limited to promoted drilling arrangements.~~

months.

Working Capital

Working capital ~~defined herein as Total current assets less Total current liabilities as set forth in our Condensed Consolidated Balance Sheets,~~(presented below) was ~~a deficit of $59.5~~$5.5 million as of September 30, ~~2019~~2020, compared to a working capital deficit of ~~$18.3~~$39.9 million as of December 31, ~~2018~~2019, representing an increase of $45.4 million. This increase consisted of a $22.1 million net increase in the fair value of our derivative contracts expected to settle in the 12 months subsequent to September 30, 2020 resulting from low oil price futures as of September 30, 2020 and a $23.3 million reduction of other net current items resulting primarily from reduced drilling activity.

The components of working capital are presented below:

	September 30,		December 31,
	2020		2019
Current assets:
Cash	$	5,311	$	13,822
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues		12,097		29,047
Joint interest billings and other, net of allowance of $80 and $83 at September 30, 2020 and December 31, 2019, respectively		11,548		6,672
Derivative asset		25,097		8,860
Prepaid expenses and other current assets		1,560		1,867
Total current assets		55,613		60,268

Current liabilities:
Accounts payable	$	6,910		25,284
Revenues and royalties payable		28,047		35,815
Accrued expenses		12,844		19,538
Asset retirement obligation		308		308
Derivative liability		1,040		6,889
Advances		93		11,505
Operating lease liabilities		768		570
Finance lease liabilities		96		206
Other current liabilities		11		43
Total current liabilities		50,117		100,158

Working Capital	$	5,496	$	(39,890	)

September 30, December 31,
2019 2018 Change
Current assets:
Cash $ 9,816
$ 376
9,440

Accounts receivable:

Oil, natural gas, and natural gas liquids revenues 14,990
13,683
1,307

Joint interest billings and other, both net of allowance of $134 8,001
4,166
3,835

Derivative asset 20,179
43,888
(23,709 ) (1)
Prepaid expenses and other current assets 2,488
1,443
1,045

Total current assets 55,474
63,556

Current liabilities:

Accounts payable $ 37,405
$ 26,452
10,953
(2)
Revenues and royalties payable 19,706
28,748
(9,042 )
Accrued expenses 35,604
22,406
13,198
(2)
Asset retirement obligation 420
557
(137 )
Advances 20,894
3,174
17,720
(3)
Derivative liability 137
528
(391 )
Operating lease liabilities 586
—
586

Finance lease liabilities 256
—
256

Total current liabilities 115,008
81,865

Working Capital $ (59,534 ) $ (18,309 ) (41,225 )


~~(1)~~	~~Primarily the result of a net decrease in fair value of our derivative contracts expected to settle over the next 12 months due to increased oil price futures.~~


~~(2)~~	~~Primarily the result of an increase in accrued but unpaid capital expenditures due to our current period drilling program.~~


~~(3)~~	At September 30, 2019, we had received advances of $12.4 million related to our Eagle Ford drilling and completion activities and $8.5 million related to our Midland drilling and completion activities.

~~We expect that changes in receivables and payables related to our pace~~

Table of development, production volumes, changes in our hedging activities, realized commodity prices and differentials to NYMEX prices for our oil and natural gas production will continue to be the largest variables affecting our working capital.Contents

We expect to finance future acquisition and development activities with cash flows from operating activities, borrowings under the EEH Credit Agreement and, various means of corporate and project financing. In addition, as indicated above, we may continue to partially finance our drilling activities through the sale of participating rights to financial institutions or industry participants, and we could structure such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate share of capital costs.

In July 2019, we entered into a Wellbore Development Agreement ("WDA") with a non-affiliated industry partner. This WDA will reduce the Company's working interest in certain wells in Reagan County. The industry partner is obligated to pay a promoted (proportionately higher) share of the capital expenditures on an initial eight wells, with an option to participate, on the same basis, in up to 11 additional wells, to earn 35% of the working interest in these wells.

Cash Flows from Operating Activities

Cash flows provided by operating activities for the nine months ended September 30, ~~2019 were $85.7~~2020 increased to $104.7 million compared to ~~$96.6~~$85.7 million for the nine months ended September 30, ~~2018,~~2019, primarily due to ~~decreased oil prices from the prior year period, offset by~~changes in timing of payments and receipts in addition to an increase in sales volumes and our settlements of derivative contracts ~~from~~as compared to the prior year period.

Cash Flows from Investing Activities

Cash flows used in investing activities for the nine months ended September 30, ~~2019 and 2018 were~~2020 decreased to $72.6 million from $121.1 million ~~and $114.4 million, respectively,~~for the nine months ended September 30, 2019, primarily due to ~~increased~~decreased drilling and completion activity as compared to the prior year ~~period.~~

period in light of the current commodity price conditions.

Cash Flows from Financing Activities

Cash flows used in financing activities decreased to $40.7 million for the nine months ended September 30, 2020 as compared to cash flows provided by financing activities of $44.8 million for the nine months ended September 30, 2019, ~~and 2018 were $44.8 million and $8.3 million, respectively,~~ primarily due to higher ~~average~~repayments and lower borrowings ~~outstanding~~ under the ~~EEH~~ Credit ~~Agreement~~Facility (as defined below) in the current year ~~period which were used to fund our drilling and completion activities.~~

period.

Capital Expenditures

Our 2019 capital budget assumes a one-rig operated program, with a temporary second rig that was deployed for the third quarter, and non-operated activities as currently proposed by operators, for our acreage in the Midland Basin as well as a 10-well program on our operated Eagle Ford acreage. Our capital expenditures for 2019 are currently estimated at approximately $205.0 million, of which we have incurred $152.4 million on an accrual basis during the first three quarters of 2019.

Our accrual basis capital expenditures for the three and nine months ended September 30, ~~2019~~2020 were as follows (in thousands):

Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019
Drilling and completions $ 77,887
$ 144,332
Leasehold costs 716
8,066
Total capital expenditures $ 78,603
$ 152,398

	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
Drilling and completions	$	1,329	$	46,303
Leasehold costs		49		139
Total capital expenditures	$	1,378	$	46,442

Credit ~~Agreement~~

~~In May, 2017,~~Facility

On November 21, 2019, Earthstone, ~~Energy Holdings, LLC (“EEH” or the~~EEH (the “Borrower”), ~~a subsidiary~~Wells Fargo, as Administrative Agent and Issuing Bank, Royal Bank of ~~Earthstone, each of Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden USA Operating, LLC, Bold Energy III LLC, Bold Operating, LLC,~~Canada, as ~~guarantors (the “Guarantors”),~~Syndication Agent, BOKF, NA dba Bank Ofof Texas (“BOKF”) as ~~Agent and Lead Arranger, Wells Fargo~~Issuing Bank ~~National Association,~~with respect to Existing Letters of Credit, Truist Bank, as ~~Syndication~~successor by merger to SunTrust Bank, as Documentation Agent, and the ~~lenders party thereto (the “Lenders”),~~Lenders entered into a credit agreement ~~(as amended, modified or restated from time to time,~~(the “Credit Facility”), which replaced the ~~“EEH Credit Agreement”).~~

~~The borrowing base under~~Company’s prior credit agreement, which was terminated on November 21, 2019.

On March 27, 2020, in connection with the ~~EEH Credit Agreement is subject to~~regularly scheduled redetermination ~~on or about May 1st and November 1st~~ of each year. The amounts borrowed under the EEH Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 1.75% to 2.75% or (b) the prime lending rate of Bank of Texas plus 0.75% to 1.75%, depending on the amounts borrowed under the EEH Credit Agreement. Principal amounts outstanding under the EEH Credit Agreement are due and payable in full at maturity on May 9, 2022. All of the obligations under the EEH Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the EEH Credit Agreement include paying a commitment fee of 0.375% or 0.50%, depending on borrowing base utilization, per year to the Lenders in respect of the unutilized commitments thereunder, as well as certain other customary fees.

The EEH Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and make distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.

In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio, as defined by the EEH Credit Agreement, of not less than 1.0 to 1.0 and a leverage ratio of not greater than 4.0 to 1.0. Leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter (excluding any debt from obligations relating to non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives) to (ii) the product of EBITDAX for such fiscal quarter multiplied by four. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) non-cash losses under

FASB ASC 815 as a result of changes in the fair market value of derivatives, (vii) exploration expenses, (viii) impairment expenses, and (ix) non-cash compensation expenses and minus (b) to the extent included in consolidated net income in such period, non-cash gains under FASB ASC 815 as a result of changes in the fair market value of derivatives.

The EEH Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of September 30, 2019, EEH was in compliance with these covenants under the EEH Credit Agreement.

~~On May 1, 2019,~~ the borrowing base under the Credit Facility, the borrowing base was set at $275 million, representing a 15% decrease from the previous borrowing base of $325 million.

On September 28, 2020, Earthstone, EEH, Wells Fargo, the guarantors party thereto, and the Lenders entered into the Amendment to the Credit ~~Agreement was increased~~Facility. Among other things, the Amendment decreased the borrowing base from ~~$275.0~~$275 million to ~~$325.0 million.~~ $240 million, increased the interest rate on outstanding borrowings by 25 to 50 basis points, increased the flexibility to finance and make acquisitions, and added certain restrictions related to dividends and distributions.

The next regularly scheduled redetermination of the borrowing base is on or around April 1, 2021.

As of September 30, ~~2019, $125.0~~2020, $130.0 million of borrowings were outstanding, bearing annual interest of ~~4.044%~~2.658%, resulting in an additional ~~$200.0~~$110.0 million of borrowing base availability under the ~~EEH~~ Credit ~~Agreement.~~

Facility.

Hedging Activities

The following table sets forth our outstanding derivative contracts at September 30, ~~2019.~~2020. When aggregating multiple contracts, the weighted average contract price is disclosed.

Period Commodity
Volume
(Bbls / MMBtu)

Price
($/Bbl / $/MMBtu)
Q4 2019 Crude Oil 671,600 $64.31
Q1 - Q4 2020 Crude Oil 2,562,000 $61.26
Q1 - Q4 2021 Crude Oil 730,000 $55.00
Q4 2019 Crude Oil Basis Swap(1) 506,000 $(5.29)
Q4 2019 Crude Oil Basis Swap(2) 92,000 $4.50
Q1 - Q4 2020 Crude Oil Basis Swap(1) 2,562,000 $(1.40)
Q1 - Q4 2021 Crude Oil Basis Swap(1) 730,000 $0.85
Q4 2019 Natural Gas 782,000 $2.85
Q1 - Q4 2020 Natural Gas 2,562,000 $2.85
Q4 2019 Natural Gas Basis Swap(3) 782,000 $(1.15)
Q1 - Q4 2020 Natural Gas Basis Swap(3) 2,562,000 $(1.07)

		Volume	Price
Period	Commodity	(Bbls / MMBtu)	($/Bbl / $/MMBtu)
Q4 2020	Crude Oil	552,000	$ 60.65
Q1 - Q4 2021	Crude Oil	1,460,000	$ 55.16
Q4 2020	Crude Oil Basis Swap (1)	598,000	$ (1.50)
Q4 2020	Crude Oil Basis Swap (2)	92,000	$ 2.55
Q4 2020	Crude Oil Roll Swap (3)	552,000	$ (1.79)
Q1 - Q4 2021	Crude Oil Basis Swap (1)	1,825,000	$ 1.05
Q4 2020	Natural Gas	644,000	$ 2.85
Q1 - Q4 2021	Natural Gas	4,380,000	$ 2.76
Q4 2020	Natural Gas Basis Swap (4)	644,000	$ (1.07)
Q1 - Q4 2021	Natural Gas Basis Swap (4)	4,380,000	$ (0.45)


(1)	The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX.


(2)	The basis differential price is between ~~LLS Argus Crude~~WTI Houston and the WTI NYMEX.

(3)

The swap is between WTI Roll and the WTI NYMEX.

~~(3)~~

(4)

The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.

Table of Contents

Obligations and Commitments

There have been no material changes from the obligations and commitments disclosed in the Obligations and Commitments section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our ~~2018~~2019 Annual Report on Form 10-K other than those described in Note ~~12.~~13. Commitments and Contingencies in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Environmental Regulations

Our operations are subject to risks normally associated with the exploration for and the production of oil and natural gas, including blowouts, fires, and environmental risks such as oil spills or natural gas leaks that could expose us to liabilities associated with these risks.

In our acquisition of existing or previously drilled well bores, we may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. We maintain comprehensive insurance coverage that we believe is adequate to mitigate the risk of any adverse financial effects associated with these risks.

However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still accrue to us. No claim has been made, nor are we aware of any liability which we may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto.

Recently Issued Accounting Standards

See Note 1. Basis of Presentation and Summary of Significant Accounting Policies in the Notes to Unaudited Condensed Consolidated Financial Statements in this report for discussion of recently issued and adopted accounting standards affecting us.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and therefore are not required to provide the information required under this item.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Securities Exchange Act of 1934, as amended (the “Exchange Act”), Rules 13a-15(e) and 15d-15(e), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Principal Accounting Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Principal Accounting Officer concluded that our disclosure controls and procedures were effective as of September 30, ~~2019~~2020 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we may be involved in various legal proceedings and claims in the ordinary course of business. As of September 30, ~~2019,~~2020, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.

See Note ~~12.~~13. Commitments and Contingencies in the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this report, which is incorporated herein by reference, for material matters that have occurred since the filing of our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~

2019.

Item 1A. Risk Factors

~~There have been no material changes from~~

In addition to the other information set forth in this report, you should carefully consider the risk factors ~~disclosed~~and other cautionary statements described in the “Risk Factors” ~~section~~sections of our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~

2019 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

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

Unregistered Sale of Equity Securities

There were no unregistered sales of equity securities during the three and nine months ended September 30, ~~2019.~~

2020.

Repurchase of Equity Securities

The following table sets forth information regarding our acquisition of shares of Class A Common Stock for the periods presented:

Total Number of Shares Purchased⁽¹⁾
Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plan or Programs
July 2019 —
$ —
—
—
August 2019 —
—
—
—
September 2019 49,111
$ 3.38
—
—

	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plan or Programs
July 2020		—	$	—		—		—
August 2020		—		—		—		—
September 2020		54,268	$	2.74		—		—

(1)

All of the shares were surrendered by employees (via net settlement) in satisfaction of tax obligations upon the vesting of restricted stock unit awards. The acquisition of the surrendered shares ~~were surrendered by employees (via net settlement) in satisfaction~~was not part of ~~tax obligations upon the vesting~~a publicly announced program to repurchase shares of ~~restricted stock unit awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of~~ our Class A Common Stock.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information.

None.

~~None.~~

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Item 6. Exhibits



Exhibit No.	Description	Filed Herewith	Furnished Herewith
31.1	Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act	X
31.2	Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act	X
32.1	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act		X
32.2	Certification of the Executive Vice President - Accounting and Administration pursuant to Section 906 of the Sarbanes-Oxley Act		X
~~101.INS~~ 101	~~XBRL Instance Document~~ Interactive Data Files (formatted as Inline XBRL).	X
~~101.SCH~~ 104	Cover Page Interactive Data File (formatted as Inline XBRL ~~Schema Document~~and contained in Exhibit 101).	X
~~101.CAL~~	~~XBRL Calculation Linkbase Document~~	X
~~101.DEF~~	~~XBRL Definition Linkbase Document~~	X
~~101.LAB~~	~~XBRL Label Linkbase Document~~	X
~~101.PRE~~	~~XBRL Presentation Linkbase Document~~	X

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.




			EARTHSTONE ENERGY, INC.

Date:	November ~~6, 2019~~4, 2020	By:	/s/ Tony Oviedo
			Tony Oviedo
			Executive Vice President – Accounting and Administration


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


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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
REVENUES
Oil	$	35,443		$	38,791		$	111,657		$	105,111
Natural gas	903			1,790			2,126			6,257
Natural gas liquids	2,858			5,495			10,691			12,753
Total revenues	39,204			46,076			124,474			124,121

OPERATING COSTS AND EXPENSES
Lease operating expense	7,259			4,843			22,531			14,509
Severance taxes	1,858			2,254			5,955			6,115
Impairment expense	—			833			—			833
Depreciation, depletion and amortization	14,079			12,842			42,281			33,362
General and administrative expense	6,230			4,944			20,528			18,809
Transaction costs	42			892			217			892
Accretion of asset retirement obligation	52			44			160			128
Total operating costs and expenses	29,520			26,652			91,672			74,648

(Loss) gain on sale of oil and gas properties	(120		)	4,096			(446		)	4,608

Income from operations	9,564			23,520			32,356			54,081

OTHER INCOME (EXPENSE)
Interest expense, net	(1,609		)	(565		)	(4,735		)	(1,788		)
Gain (loss) on derivative contracts, net	18,726			(17,481		)	(19,672		)	(33,606		)
Litigation settlement	—			(4,775		)	—			(4,775		)
Other income (expense), net	21			37			(1		)	434
Total other income (expense)	17,138			(22,784		)	(24,408		)	(39,735		)

Income before income taxes	26,702			736			7,948			14,346
Income tax expense	(575		)	(172		)	(728		)	(119		)
Net income	26,127			564			7,220			14,227

Less: Net income attributable to noncontrolling interest	14,357			340			3,877			8,032

Net income attributable to Earthstone Energy, Inc.	$	11,770		$	224		$	3,343		$	6,195

Net income per common share attributable to Earthstone Energy, Inc.:
Basic	$	0.41		$	0.01		$	0.12		$	0.22
Diluted	$	0.41		$	0.01		$	0.12		$	0.22

Weighted average common shares outstanding:
Basic	29,032,842			28,257,376			28,883,907			28,011,298
Diluted	29,032,842			28,311,759			28,883,907			28,108,365



	Issued Shares
	Class A Common Stock		Class B Common Stock		Class A Common Stock		Class B Common Stock		Additional Paid-in Capital			Accumulated Deficit			Total Earthstone Energy, Inc. Equity			Noncontrolling Interest			Total Equity
At December 31, 2018	28,696,321		35,452,178		$	29	$	35	$	517,073		$	(182,497	)	$	334,640		$	491,852		$	826,492
ASC 842 implementation	—		—		—		—		—			67			67			99			166
Stock-based compensation expense	—		—		—		—		2,212			—			2,212						2,212
Vesting of restricted stock units, net of taxes paid	166,140		—		—		—		—			—			—			—			—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings	59,261		—		—		—		(396		)	—			(396		)	—			(396		)
Cancellation of treasury shares	(59,261	)	—		—		—		—			—			—			—			—
Net loss	—		—		—		—		—			(17,204		)	(17,204		)	(21,239		)	(38,443		)
At March 31, 2019	28,862,461		35,452,178		$	29	$	35	$	518,889		$	(199,634	)	$	319,319		$	470,712		$	790,031
Stock-based compensation expense	—		—		—		—		2,261			—			2,261						2,261
Vesting of restricted stock units, net of taxes paid	133,311		—		—		—		—			—			—			—			—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings	43,344		—		—		—		(265		)	—			(265		)	—			(265		)
Cancellation of treasury shares	(43,344	)	—		—		—		—			—			—			—			—
Class B Common Stock converted to Class A Common Stock	35,732		(35,732	)	—		—		476			—			476			(476		)	—
Net income	—		—		—		—		—			8,777			8,777			10,759			19,536
At June 30, 2019	29,031,504		35,416,446		$	29	$	35	$	521,361		$	(190,857	)	$	330,568		$	480,995		$	811,563
Stock-based compensation expense	—		—		—		—		2,207			—			2,207						2,207
Vesting of restricted stock units, net of taxes paid	118,716		—		—		—		—			—			—			—			—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings	49,111		—		—		—		(166		)	—			(166		)	—			(166		)
Cancellation of treasury shares	(49,111	)	—		—		—		—			—			—			—			—
Net income	—		—		—		—		—			11,770			11,770			14,357			26,127
At September 30, 2019	29,150,220		35,416,446		$	29	$	35	$	523,402		$	(179,087	)	$	344,379		$	495,352		$	839,731



	For the Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities:
Net income	$	7,220		$	14,227
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties	—			833
Depreciation, depletion and amortization	42,281			33,362
Accretion of asset retirement obligations	160			128
Settlement of asset retirement obligations	(179		)	(79		)
Loss (gain) on sale of oil and gas properties	446			(4,608		)
Total loss on derivative contracts, net	19,672			33,606
Operating portion of net cash received (paid) in settlement of derivative contracts	13,660			(13,643		)
Stock-based compensation	6,680			5,535
Deferred income taxes	728			119
Amortization of deferred financing costs	336			228
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(5,585		)	(1,476		)
(Increase) decrease in prepaid expenses and other current assets	(28		)	(372		)
Increase (decrease) in accounts payable and accrued expenses	(8,330		)	3,939
Increase (decrease) in revenues and royalties payable	(9,042		)	26,572
Increase (decrease) in advances	17,720			(1,816		)
Net cash provided by operating activities	85,739			96,555
Cash flows from investing activities:
Additions to oil and gas properties	(120,685		)	(120,124		)
Additions to office and other equipment	(379		)	(121		)
Proceeds from sales of oil and gas properties	2			5,840
Net cash used in investing activities	(121,062		)	(114,405		)
Cash flows from financing activities:
Proceeds from borrowings	165,272			70,308
Repayments of borrowings	(119,099		)	(60,308		)
Cash paid related to the exchange and cancellation of Class A Common Stock	(827		)	(1,402		)
Cash paid for finance leases	(355		)	—
Deferred financing costs	(228		)	(274		)
Net cash provided by financing activities	44,763			8,324
Net increase (decrease) in cash	9,440			(9,526		)
Cash at beginning of period	376			22,955
Cash at end of period	$	9,816		$	13,429
Supplemental disclosure of cash flow information
Cash paid for:
Interest	$	4,235		$	1,480
Non-cash investing and financing activities:
Accrued capital expenditures	$	50,615		$	11,314
Lease asset additions - ASC 842	$	4,710		$	—
Asset retirement obligations	$	43		$	(120	)



September 30, 2019	Level 1		Level 2		Level 3		Total
Financial assets
Derivative asset - current	$	—	$	20,179	$	—	$	20,179
Derivative asset - noncurrent	—		9,246		—		9,246
Total financial assets	$	—	$	29,425	$	—	$	29,425

Financial liabilities
Derivative liability - current	$	—	$	137	$	—	$	137
Derivative liability - noncurrent	—		29		—		29
Total financial liabilities	$	—	$	166	$	—	$	166

December 31, 2018
Financial assets
Derivative asset - current	$	—	$	43,888	$	—	$	43,888
Derivative asset - noncurrent			21,121				21,121
Total financial assets	$	—	$	65,009	$	—	$	65,009

Financial liabilities
Derivative liability - current	$	—	$	528	$	—	$	528
Derivative liability - noncurrent	—		1,891		—		1,891
Total financial liabilities	$	—	$	2,419	$	—	$	2,419



	Price Swaps
Period	Commodity	Volume (Bbls / MMBtu)	Weighted Average Price ($/Bbl / $/MMBtu)
Q4 2019	Crude Oil	671,600	$	64.31
Q1 - Q4 2020	Crude Oil	2,562,000	$	61.26
Q1 - Q4 2021	Crude Oil	730,000	$	55.00
Q4 2019	Crude Oil Basis Swap(1)	506,000	$	(5.29	)
Q4 2019	Crude Oil Basis Swap(2)	92,000	$	4.50
Q1 - Q4 2020	Crude Oil Basis Swap(1)	2,562,000	$	(1.40	)
Q1 - Q4 2021	Crude Oil Basis Swap(1)	730,000	$	0.85
Q4 2019	Natural Gas	782,000	$	2.85
Q1 - Q4 2020	Natural Gas	2,562,000	$	2.85
Q4 2019	Natural Gas Basis Swap(3)	782,000	$	(1.15	)
Q1 - Q4 2020	Natural Gas Basis Swap(3)	2,562,000	$	(1.07	)



		September 30, 2019							December 31, 2018
Derivatives not designated as hedging contracts under ASC Topic 815	Balance Sheet Location	Gross Recognized Assets / Liabilities		Gross Amounts Offset			Net Recognized Assets / Liabilities		Gross Recognized Assets / Liabilities		Gross Amounts Offset			Net Recognized Assets / Liabilities
Commodity contracts	Derivative asset - current	$	27,014	$	(6,835	)	$	20,179	$	48,662	$	(4,774	)	$	43,888
Commodity contracts	Derivative liability - current	$	6,972	$	(6,835	)	$	137	$	5,302	$	(4,774	)	$	528
Commodity contracts	Derivative asset - noncurrent	$	10,650	$	(1,404	)	$	9,246	$	23,605	$	(2,484	)	$	21,121
Commodity contracts	Derivative liability - noncurrent	$	1,433	$	(1,404	)	$	29	$	4,375	$	(2,484	)	$	1,891



Derivatives not designated as hedging contracts under ASC Topic 815			Three Months Ended September 30,					Nine Months Ended September 30,
	Statement of Cash Flows Location	Statement of Operations Location	2019		2018			2019			2018
Unrealized gain (loss)	Not separately presented	Not separately presented	$	15,021	$	(13,105	)	$	(33,332	)	$	(19,963	)
Realized gain (loss)	Operating portion of net cash paid in settlement of derivative contracts	Not separately presented	3,705		(4,376		)	13,660			(13,643		)
	Total gain (loss) on derivative contracts, net	Gain (loss) on derivative contracts, net	$	18,726	$	(17,481	)	$	(19,672	)	$	(33,606	)



	EEH Units Held By Earthstone and Lynden US	%		EEH Units Held By Others		%		Total EEH Units Outstanding
As of December 31, 2018	28,696,321	44.7	%	35,452,178		55.3	%	64,148,499
EEH Units and Class B Common Stock converted to Class A Common Stock	35,732			(35,732	)			—
EEH Units issued in connection with the vesting of restricted stock units	418,167			—				418,167
As of September 30, 2019	29,150,220	45.1	%	35,416,446		54.9	%	64,566,666



	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands, except per share amounts)	2019		2018		2019		2018
Net income attributable to Earthstone Energy, Inc.	$	11,770	$	224	$	3,343	$	6,195

Net income per common share attributable to Earthstone Energy, Inc.:
Basic	$	0.41	$	0.01	$	0.12	$	0.22
Diluted	$	0.41	$	0.01	$	0.12	$	0.22

Weighted average common shares outstanding
Basic	29,032,842		28,257,376		28,883,907		28,011,298
Add potentially dilutive securities:
Unvested restricted stock units	—		54,383		—		97,067
Unvested performance units	—		—		—		—
Diluted weighted average common shares outstanding	29,032,842		28,311,759		28,883,907		28,108,365



	Shares		Weighted-Average Grant Date Fair Value
Unvested RSUs at December 31, 2018	810,995		$	8.83
Granted	762,350		$	6.39
Forfeited	(23,084	)	$	7.64
Vested	(569,883	)	$	8.14
Unvested RSUs at September 30, 2019	980,378		$	7.36



	Shares	Weighted-Average Grant Date Fair Value
Unvested PSUs at December 31, 2018	252,500	$	13.75
Granted	669,550	$	9.30
Unvested PSUs at September 30, 2019	922,050	$	10.52



	2019
Beginning asset retirement obligations	$	2,229
Liabilities incurred	43
Liabilities settled	(179		)
Accretion expense	160
Ending asset retirement obligations	$	2,253



Leases	Balance Sheet Location
Assets
Noncurrent:
Operating	Operating lease right-of-use assets	$	3,295
Finance	Office and other equipment, net of accumulated depreciation and amortization	630
Total lease assets		$	3,925

Liabilities
Current:
Operating	Operating lease liabilities	$	586
Finance	Finance lease liabilities	256
Noncurrent:
Operating	Operating lease liabilities	2,722
Finance	Finance lease liabilities	111
Total lease liabilities		$	3,675



	Operating			Finance
2019 (excluding nine months ended September 30, 2019)	$	207		$	81
2020	632			219
2021	791			84
2022	696			5
2023	596			—
Thereafter	757			—
Total lease payments	$	3,679		$	389
Less imputed interest	(371		)	(22		)
Total lease liability	$	3,308		$	367



	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Drilling and completions	$	77,887	$	144,332
Leasehold costs	716		8,066
Total capital expenditures	$	78,603	$	152,398



	Total Number of Shares Purchased⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plan or Programs
July 2019	—	$	—	—	—
August 2019	—	—		—	—
September 2019	49,111	$	3.38	—	—