EARTHSTONE ENERGY INC - Quarter Report: 2019 June (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________________

FORM 10-Q

_________________________________________________________

(Mark One)



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

For the Quarterly Period Ended June 30, 2019



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

Commission File No. 001-35049

_________________________________________________________

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

_________________________________________________________



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 Exchange Act during the past 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 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. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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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 August 1, 2019, 29,031,504 shares of Class A Common Stock, $0.001 par value per share, and 35,416,446 shares of Class B Common Stock, $0.001 par value per share, were outstanding.

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		Page

	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	4
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018	6
	Condensed Consolidated Statements of Equity for the Six Months Ended June 30, 2019 and 2018	7
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	9
	Notes to Unaudited Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	33

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	36
	Signatures	37

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except share and per share amounts)



	June 30,			December 31,
ASSETS	2019			2018
Current assets:
Cash	$	5,785		$	376
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	13,464			13,683
Joint interest billings and other, net of allowance of $133 and $134 at June 30, 2019 and December 31, 2018, respectively	8,870			4,166
Derivative asset	8,578			43,888
Prepaid expenses and other current assets	6,692			1,443
Total current assets	43,389			63,556

Oil and gas properties, successful efforts method:
Proved properties	823,266			755,443
Unproved properties	272,007			266,140
Land	5,382			5,382
Total oil and gas properties	1,100,655			1,026,965

Accumulated depreciation, depletion and amortization	(155,085		)	(127,256		)
Net oil and gas properties	945,570			899,709

Other noncurrent assets:
Goodwill	17,620			17,620
Office and other equipment, net of accumulated depreciation and amortization of $2,857 and $2,490 at June 30, 2019 and December 31, 2018, respectively	1,350			662
Derivative asset	6,934			21,121
Operating lease right-of-use assets	870			—
Other noncurrent assets	1,615			1,640
TOTAL ASSETS	$	1,017,348		$	1,004,308
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	21,497		$	26,452
Revenues and royalties payable	24,904			28,748
Accrued expenses	21,260			22,406
Asset retirement obligation	410			557
Advances	9,647			3,174
Derivative liability	176			528
Operating lease liabilities	507			—
Finance lease liabilities	318			—
Total current liabilities	78,719			81,865

Noncurrent liabilities:
Long-term debt	110,000			78,828
Deferred tax liability	13,642			13,489
Asset retirement obligation	1,771			1,672
Derivative liability	1,099			1,891

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Operating lease liabilities	394			—
Finance lease liabilities	160			—
Other noncurrent liabilities	—			71
Total noncurrent liabilities	127,066			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; 29,031,504 and 28,696,321 issued and outstanding at June 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 June 30, 2019 and December 31, 2018, respectively	35			35
Additional paid-in capital	521,361			517,073
Accumulated deficit	(190,857		)	(182,497		)
Total Earthstone Energy, Inc. equity	330,568			334,640
Noncontrolling interest	480,995			491,852
Total equity	811,563			826,492

TOTAL LIABILITIES AND EQUITY	$	1,017,348		$	1,004,308

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 OPERATIONS (UNAUDITED)

(In thousands, except share and per share amounts)



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
REVENUES
Oil	$	40,767		$	31,903		$	76,214		$	66,320
Natural gas	129			1,783			1,223			4,467
Natural gas liquids	3,646			3,464			7,833			7,258
Total revenues	44,542			37,150			85,270			78,045

OPERATING COSTS AND EXPENSES
Lease operating expense	8,605			5,009			15,272			9,666
Severance taxes	2,109			1,824			4,097			3,861
Depreciation, depletion and amortization	14,197			10,812			28,202			20,520
General and administrative expense	7,028			7,286			14,298			13,865
Transaction costs	—			—			175			—
Accretion of asset retirement obligation	54			43			108			84
Total operating costs and expenses	31,993			24,974			62,152			47,996

(Loss) gain on sale of oil and gas properties	(201		)	63			(326		)	512

Income from operations	12,348			12,239			22,792			30,561

OTHER INCOME (EXPENSE)
Interest expense, net	(1,677		)	(610		)	(3,126		)	(1,223		)
Gain (loss) on derivative contracts, net	9,496			(10,850		)	(38,398		)	(16,125		)
Other (expense) income, net	(18		)	391			(22		)	397
Total other income (expense)	7,801			(11,069		)	(41,546		)	(16,951		)

Income (loss) before income taxes	20,149			1,170			(18,754		)	13,610
Income tax (expense) benefit	(613		)	302			(153		)	53
Net income (loss)	19,536			1,472			(18,907		)	13,663

Less: Net income (loss) attributable to noncontrolling interest	10,759			822			(10,480		)	7,692

Net income (loss) attributable to Earthstone Energy, Inc.	$	8,777		$	650		$	(8,427	)	$	5,971

Net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic	$	0.30		$	0.02		$	(0.29	)	$	0.21
Diluted	$	0.30		$	0.02		$	(0.29	)	$	0.21

Weighted average common shares outstanding:
Basic	28,895,893			27,987,509			28,808,205			27,886,220
Diluted	29,228,886			28,036,052			28,808,205			27,967,421

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 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, 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

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	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

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 Six Months Ended June 30,
	2019			2018
Cash flows from operating activities:
Net (loss) income	$	(18,907	)	$	13,663
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	28,202			20,520
Accretion of asset retirement obligations	108			84
Settlement of asset retirement obligations	(179		)	(79		)
Loss (gain) on sale of oil and gas properties	326			(512		)
Total loss on derivative contracts, net	38,398			16,125
Operating portion of net cash received (paid) in settlement of derivative contracts	9,956			(9,267		)
Stock-based compensation	4,473			4,013
Deferred income taxes	153			(53		)
Amortization of deferred financing costs	215			143
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(1,257		)	4,475
(Increase) decrease in prepaid expenses and other current assets	(537		)	(992		)
Increase (decrease) in accounts payable and accrued expenses	(5,222		)	(17,287		)
Increase (decrease) in revenues and royalties payable	(3,845		)	8,437
Increase in advances	3,400			14,159
Net cash provided by operating activities	55,284			53,429
Cash flows from investing activities:
Additions to oil and gas properties	(79,760		)	(68,516		)
Additions to office and other equipment	(202		)	(53		)
Proceeds from sales of oil and gas properties	2			210
Net cash used in investing activities	(79,960		)	(68,359		)
Cash flows from financing activities:
Proceeds from borrowings	128,087			25,000
Repayments of borrowings	(96,915		)	(27,500		)
Cash paid related to the exchange and cancellation of Class A Common Stock	(661		)	(1,116		)
Cash paid for finance leases	(237		)	—
Deferred financing costs	(189		)	(213		)
Net cash provided by (used in) financing activities	30,085			(3,829		)
Net increase (decrease) in cash	5,409			(18,759		)
Cash at beginning of period	376			22,955
Cash at end of period	$	5,785		$	4,196
Supplemental disclosure of cash flow information
Cash paid for:
Interest	$	2,760		$	986
Non-cash investing and financing activities:
Accrued capital expenditures	$	16,714		$	25,791
Lease asset additions - ASC 842	$	1,573		$	—
Asset retirement obligations	$	23		$	(141	)

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" and together with its consolidated subsidiaries, the "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 Annual Report on Form 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 is derived from the audited Consolidated Financial Statements at that date.

Recently Issued Accounting Standards

Leases – In February 2016, the Financial Accounting Standards Board ("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 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.

Intangibles - Goodwill and Other – In January 2017, the FASB issued updated guidance simplifying the test for goodwill impairment. The update eliminates Step 2 of the goodwill impairment test. Instead, an entity should perform its annual or interim goodwill

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

impairment test by comparing the fair value 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 fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. 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 is in the process of evaluating the impact of this guidance, if any, on its Consolidated Financial Statements.

Fair Value Measurements – In August 2018, the FASB issued an update 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 is in the process of evaluating the impact of this update, if any, on its Consolidated Financial Statements.

Note 2. Fair Value Measurements

FASB 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 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 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 six months ended June 30, 2019.

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. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The swaps are also designated as Level 2 within the valuation hierarchy.

The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure 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):

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)



June 30, 2019	Level 1		Level 2		Level 3		Total
Financial assets
Derivative asset - current	$	—	$	8,578	$	—	$	8,578
Derivative asset - noncurrent	—		6,934		—		6,934
Total financial assets	$	—	$	15,512	$	—	$	15,512

Financial liabilities
Derivative liability - current	$	—	$	176	$	—	$	176
Derivative liability - noncurrent	—		1,099		—		1,099
Total financial liabilities	$	—	$	1,275	$	—	$	1,275

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

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 and goodwill. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances.

Proved Oil and Natural Gas Properties

Proved oil and natural gas properties are measured at fair value on a nonrecurring basis in order to review for impairment. 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.

Goodwill

Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the fair value of goodwill may be less than its carrying amount. Such test includes an assessment of qualitative and quantitative factors.

Business Combinations

The Company accounts for its acquisitions of oil and gas properties not commonly controlled in accordance with FASB ASC Topic 805, Business Combinations, which, among other things, requires the Company to determine if an asset or a business has been

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acquired. If the Company determines an asset(s) has been acquired, the asset(s) acquired, as well as any liabilities assumed, are measured and recorded at the acquisition date cost. If the Company determines a business has been acquired, the assets acquired and liabilities assumed are measured and recorded at their fair values as of the acquisition date, recording goodwill for amounts paid in excess of fair value.

Asset Retirement Obligations

The estimated fair value of the Company's asset retirement obligation at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company's credit risk, and the time value of money to the undiscounted expected abandonment cash flows, including estimates of plugging, abandonment and remediation costs and well life. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy. See Note 10. Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

Performance Units

Stock-based compensation related to performance is estimated utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes fair value based on the most likely outcome, and has been classified as Level 3 in the fair value hierarchy. Stock-based compensation related to performance units is described in Note 8. Stock-Based Compensation.

Note 3. Derivative Financial Instruments

The Company’s hedging activities 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.

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.

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



	Price Swaps
Period	Commodity	Volume (Bbls / MMBtu)	Weighted Average Price ($/Bbl / $/MMBtu)
Q3 - Q4 2019	Crude Oil	1,177,600	$	65.64
Q1 - Q4 2020	Crude Oil	1,830,000	$	63.80
Q1 - Q4 2021	Crude Oil	365,000	$	55.53
Q3 - Q4 2019	Crude Oil Basis Swap(1)	1,012,000	$	(5.29	)
Q3 - Q4 2019	Crude Oil Basis Swap(2)	184,000	$	4.50
Q1 - Q4 2020	Crude Oil Basis Swap(1)	1,830,000	$	(2.14	)
Q3 - Q4 2019	Natural Gas	1,564,000	$	2.85
Q1 - Q4 2020	Natural Gas	2,562,000	$	2.85
Q3 - Q4 2019	Natural Gas Basis Swap(3)	1,564,000	$	(1.16	)
Q1 - Q4 2020	Natural Gas Basis Swap(3)	2,562,000	$	(1.07	)


(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 and the WTI NYMEX.


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

Subsequent to June 30, 2019, the Company entered into additional hedges consisting of Crude Oil Swaps on 731 MBbls at a price of $54.47/Bbl for 2020 and 2021, WTI Midland Argus Crude Basis Swaps on 366 MBbls at a price of $0.55/Bbl for 2020 and WTI Midland Argus Crude Basis Swaps on 730 MBbls at a price of $0.85/Bbl for 2021.

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):



		June 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	$	17,346	$	(8,768	)	$	8,578	$	48,662	$	(4,774	)	$	43,888
Commodity contracts	Derivative liability - current	$	8,944	$	(8,768	)	$	176	$	5,302	$	(4,774	)	$	528
Commodity contracts	Derivative asset - noncurrent	$	8,583	$	(1,649	)	$	6,934	$	23,605	$	(2,484	)	$	21,121
Commodity contracts	Derivative liability - noncurrent	$	2,748	$	(1,649	)	$	1,099	$	4,375	$	(2,484	)	$	1,891

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 (in thousands):



Derivatives not designated as hedging contracts under ASC Topic 815			Three Months Ended June 30,					Six Months Ended June 30,
	Statement of Cash Flows Location	Statement of Operations Location	2019		2018			2019			2018
Unrealized gain (loss)	Not separately presented	Not separately presented	$	4,902	$	(5,858	)	$	(48,354	)	$	(6,858	)
Realized gain (loss)	Operating portion of net cash paid in settlement of derivative contracts	Not separately presented	4,594		(4,992		)	9,956			(9,267		)
	Total gain (loss) on derivative contracts, net	Gain (loss) on derivative contracts, net	$	9,496	$	(10,850	)	$	(38,398	)	$	(16,125	)

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Note 4. 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 (loss) 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 six months ended June 30, 2019, depletion expense for oil and gas producing property and related equipment was $14.0 million and $27.8 million, respectively. For the three and six months ended June 30, 2018, depletion expense for oil and gas producing property and related equipment was $10.7 million and $20.3 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 delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling 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 six months ended June 30, 2019 and 2018, the Company did not record any impairments to its oil and natural gas properties.

Note 5. 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 income (loss) attributable to noncontrolling interest in the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2019 represents the portion of net income or loss 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 June 30, 2019 and December 31, 2018 represents the portion of net assets of the Company attributable to the members of EEH other than Earthstone and Lynden US.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table presents the changes in noncontrolling interest for the six months ended June 30, 2019:



	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	299,451			—				299,451
As of June 30, 2019	29,031,504	45.0	%	35,416,446		55.0	%	64,447,950

Note 6. Net Income (Loss) Per Common Share

Net income (loss) per common share—basic is calculated by dividing Net income (loss) by the weighted average number of shares of common stock outstanding during the period. Net income (loss) per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income (loss) by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income (loss) 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 income (loss) per common share is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands, except per share amounts)	2019		2018		2019			2018
Net income (loss) attributable to Earthstone Energy, Inc.	$	8,777	$	650	$	(8,427	)	$	5,971

Net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic	$	0.30	$	0.02	$	(0.29	)	$	0.21
Diluted	$	0.30	$	0.02	$	(0.29	)	$	0.21

Weighted average common shares outstanding
Basic	28,895,893		27,987,509		28,808,205			27,886,220
Add potentially dilutive securities:
Unvested restricted stock units	—		48,543		—			81,201
Unvested performance units	332,993		—		—			—
Diluted weighted average common shares outstanding	29,228,886		28,036,052		28,808,205			27,967,421

Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and net income attributable to noncontrolling interest of $10.8 million for the three months ended June 30, 2019 and net loss attributable to noncontrolling interest of $10.5 million for the six months ended June 30, 2019 would be added back to Net income (loss) attributable to Earthstone Energy, Inc. for the periods then ended, having no dilutive effect on Net income (loss) per common share attributable to Earthstone Energy, Inc. For the six months ended June 30, 2019, the Company excluded 348,224 shares for the dilutive effect of performance units in calculating diluted earnings per share as the effect was anti-dilutive due to the net loss incurred the period.

Note 7. Common Stock

Class A Common Stock

At June 30, 2019 and December 31, 2018, there were 29,031,504 and 28,696,321 shares of Class A Common Stock issued and outstanding, respectively. During the three and six months ended June 30, 2019, as a result of the vesting and settlement of restricted

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stock units under the Earthstone Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan (the "2014 Plan"), Earthstone issued 176,655 and 402,056 shares, respectively, of Class A Common Stock, of which 43,344 and 102,605 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 six months ended June 30, 2018, as a result of the vesting and settlement of restricted stock units under the 2014 Plan, Earthstone issued 339,075 and 454,011 shares, respectively, of Class A Common Stock, of which 83,762 and 112,426 shares, respectively, of Class A Common Stock were retained as treasury stock and canceled to satisfy the related employee income tax liability.

Class B Common Stock

At June 30, 2019 and December 31, 2018, there were 35,416,446 and 35,452,178 shares of Class B Common Stock issued and outstanding, respectively. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock. During the three and six months ended June 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 six months ended June 30, 2018, 11,195 and 205,241 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. Stock-Based Compensation

Restricted Stock Units

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

Each RSU represents the contingent right to receive one 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 six months ended June 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	(20,251	)	$	7.52
Vested	(402,056	)	$	8.28
Unvested RSUs at June 30, 2019	1,151,038		$	7.43

As of June 30, 2019, there was $8.3 million of unrecognized compensation expense related to the RSU awards which will be recognized over a weighted average period of 1.02 years.

For the three and six months ended June 30, 2019, Stock-based compensation related to RSUs was $1.5 million and $3.0 million, respectively. For the three and six months ended June 30, 2018, Stock-based compensation related to RSUs was $1.8 million and $3.6 million, respectively.

Performance Units

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The table below summarizes performance unit (“PSU”) activity for the six months ended June 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 June 30, 2019	922,050	$	10.52

On January 28, 2019, the Board of Directors of Earthstone (the "Board") granted 669,550 PSUs to certain executive officers pursuant to the 2014 Plan. The 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 and ending on January 31, 2022 (the “Performance Period”) of performance criteria established by the Board.

The number of shares of Class A Common Stock that may be issued will be determined by multiplying the number of PSUs granted by the Relative Total Shareholder Return ("TSR") Percentage (0% 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.

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 PSUs granted on January 28, 2019, assuming a risk-free rate of 2.6% and volatilities ranging from 40.1% to 114.1%, the Company calculated the weighted average grant date fair value per PSU to be $9.30.

As of June 30, 2019, there was $7.3 million of unrecognized compensation expense related to the PSU awards which will be amortized over a weighted average period of 1.21 years.

For the three and six months ended June 30, 2019, Stock-based compensation related to the PSUs was approximately $0.8 million and $1.4 million, respectively. For the three and six months ended June 30, 2018, Stock-based compensation related to the PSUs was approximately $0.3 million and $0.4 million, respectively.

Note 9. Long-Term Debt

Credit Agreement

In May, 2017, Earthstone Energy Holdings, LLC (“EEH” or the “Borrower”), a subsidiary 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"), Bold Operating, LLC, as guarantors (the “Guarantors”), BOKF, NA dba Bank Of Texas, as Agent and Lead Arranger, Wells Fargo Bank, National Association, as Syndication Agent, and the lenders party thereto (the “Lenders”), entered into a credit agreement (as amended, modified or restated from time to time, the “EEH Credit Agreement”).

The borrowing base under the EEH Credit Agreement is subject to 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.

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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 June 30, 2019, 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. As of June 30, 2019, $110.0 million of borrowings were outstanding, bearing annual interest of 4.390%, resulting in an additional $215.0 million of borrowing base availability under the EEH Credit Agreement. At December 31, 2018, there were $78.8 million of borrowings outstanding under the EEH Credit Agreement.

For the six months ended June 30, 2019, the Company had borrowings of $128.1 million and $96.9 million in repayments of borrowings.

For the three and six months ended June 30, 2019, interest on borrowings averaged 4.58% and 4.61% per annum, respectively, which excluded commitment fees of $0.2 million and $0.3 million, respectively, and amortization of deferred financing costs of $0.1 million and $0.2 million, respectively. For the three and six months ended June 30, 2018, interest on borrowings averaged 3.66% and 3.64% per annum, respectively, which excluded commitment fees of $0.3 million and $0.5 million, respectively, and amortization of deferred financing costs of $0.1 million and $0.1 million, respectively.

During the three and six months ended June 30, 2019, $0.2 million of costs associated with the EEH Credit Agreement were capitalized. The Company capitalized $0.2 million of costs associated with the EEH Credit Agreement for the six months ended June 30, 2018. 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.

Note 10. 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.

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



	2019
Beginning asset retirement obligations	$	2,229
Liabilities incurred	23
Liabilities settled	(179		)
Accretion expense	108
Divestitures	—
Revision of estimates	—
Ending asset retirement obligations	$	2,181

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11. 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 10.2% 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 June 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 $4.0 million and $8.3 million and received payments from Flatonia of $1.6 million and $2.9 million for the three and six months ended June 30, 2019, respectively. For the three and six months ended June 30, 2018, the Company made payments to Flatonia of $6.1 million and $12.4 million and received payments from Flatonia of $2.0 million and $4.1 million, respectively. At June 30, 2019 and December 31, 2018, amounts receivable from Flatonia in connection with the Operating Agreement were $1.0 million and $0.8 million, respectively. Payables related to revenues outstanding and due to Flatonia as of June 30, 2019 and December 31, 2018 were $1.3 million and $1.6 million, respectively.

Earthstone's majority shareholder consists of various investment funds managed by a venture capital firm who may manage other investments in entities with which the Company interacts in the normal course of business.

Note 12. Commitments and Contingencies

Legal

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

Olenik v. Lodzinksi 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"), Bold, Bold Energy Holdings, LLC ("Bold Holdings") and Oak Valley Resources. The complaint alleges that Earthstone’s directors breached their fiduciary duties in connection with the contribution dated as of November 7, 2016 and as amended on March 21, 2017 (the "Bold Contribution Agreement"), by and among Earthstone, EEH, Lynden US, Lynden USA Operating, LLC, Bold Holdings and Bold. The Plaintiff asserts that the directors negotiated 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 up to March 13, 2017, excluding defendants and their affiliates. On July 20, 2018, the Delaware Court of Chancery granted the 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 and each of the other defendants believe the claims are entirely without merit and intend to mount a vigorous defense. The ultimate outcome of this suit is uncertain, and while Earthstone is confident in its position, any potential monetary recovery or loss to Earthstone cannot be estimated at this time.

Environmental and Regulatory

As of June 30, 2019, 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.

Note 13. 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

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 six months ended June 30, 2019, the Company recorded income tax expense of approximately $0.2 million which included (1) income tax benefit for Lynden US of $0.4 million as a result of its share of the distributable loss from EEH, (2) no net income tax benefit for Earthstone as the $1.6 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 six months ended June 30, 2019.

During the six months ended June 30, 2018, the Company recorded a net income tax benefit of approximately $0.1 million which included (1) income tax expense for Lynden US of $0.2 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 $0.9 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation recorded against its deferred tax asset as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $0.2 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the six months ended June 30, 2018.

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 June 30, 2019 for our leases is as follows (in thousands):



Leases	Balance Sheet Location
Assets
Noncurrent:
Operating	Operating lease right-of-use assets	$	870
Finance	Office and other equipment, net of accumulated depreciation and amortization	703
Total lease assets		$	1,573

Liabilities
Current:
Operating	Operating lease liabilities	$	507
Finance	Finance lease liabilities	318
Noncurrent:
Operating	Operating lease liabilities	394
Finance	Finance lease liabilities	160
Total lease liabilities		$	1,379

*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 six months ended June 30, 2019 were $0.2 million and $0.4 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 six months ended June 30, 2019 were $0.1 million and $0.2 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 $2.0 million and $4.1 million of short-term lease costs

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

related to drilling rig contracts during the three and six months ended June 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 June 30, 2019 are as follows (in thousands):



	Operating			Finance
2019 (excluding six months ended June 30, 2019)	$	414		$	188
2020	206			232
2021	215			84
2022	110			5
2023	—			—
Thereafter	—			—
Total lease payments	$	945		$	509
Less imputed interest	(44		)	(31		)
Total lease liability	$	901		$	478

Cash payments for our operating leases were $0.2 million and $0.4 million, respectively, for the three and six months ended June 30, 2019. Cash payments for our finance leases were $0.1 million and $0.2 million, respectively, for the three and six months ended June 30, 2019. There were no right-of-use assets obtained in exchange for lease obligations for our operating leases for the three months ended June 30, 2019. For the six months ended June 30, 2019 there were $0.6 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 June 30, 2019, the weighted average remaining lease terms of our operating and finance leases were 2.1 years and 1.7 years, respectively. The weighted average discount rates used to determine the lease liabilities as of June 30, 2019 for our operating and finance leases were 4.35% and 6.91%, 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.

In July 2019, our corporate office lease was extended through December 2025 which is expected to increase operating lease right-of-use assets and operating lease liabilities by approximately $2.4 million. The lease extension commences on January 1, 2020.

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 Annual Report on Form 10-K that was 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, which are included in our 2018 Annual Report on Form 10-K.

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Overview

Earthstone Energy, Inc., a Delaware corporation ("Earthstone" and together with our consolidated subsidiaries, the "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

Our plans include a continued focus on the Midland Basin through the development of our properties and by further expansion of our acreage footprint as an operator. Our development program for 2019 presently includes drilling approximately 19.0 gross/14.7 net operated wells and completing 17.0 gross/12.6 net of these operated wells. In addition, we have assumed participating in drilling 20.0 gross/5.0 net wells and completing 5.0 gross/2.0 net wells where we have a non-operated working interest. At our Eagle Ford Trend properties, our development program includes drilling 10.0 gross/5.1 net operated wells and completing all of these operated wells. In order to achieve these plans, we have an approved annual budget of $205.0 million. Commodity prices continue to be volatile and we intend to be vigilant to adjust our business plans accordingly.

In addition to our 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. Our intent is to increase our overall operated locations and allow us to develop our acreage with long horizontal laterals (7,500 to 12,000+ foot lateral lengths). We will also remain active in seeking M&A transactions in this high economic return geographic area.

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

We completed 13 gross wells (3.0 gross/2.9 net operated and 10.0 gross/1.5 net non-operated) and spud an additional 19 gross wells (10.0 gross/8.4 net operated and 9.0 gross/3.0 net non-operated) through the first half of 2019. We currently expect to complete approximately 14.0 gross/9.7 net operated wells over the second half of 2019. We intend 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 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.

Commencing in early 2018, market concerns regarding future take-away capacity adversely affected oil and gas price differentials in the Midland Basin. Since then, the market concerns have been abated as additional oil pipelines have been added to the take-away infrastructure in the area. Consequently, we have experienced significant improvement in these negative oil price differentials. Natural gas price differentials continue to grow as future take-away capacity in the area is being challenged. However, there are some additional gas pipelines expected to be brought online during the fourth quarter of 2019. 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 are being negatively impacted by differentials (excluding the impact of derivatives). Increasing and sustained negative oil and gas price differentials will adversely affect our future cash flows and could cause us to reduce the pace of development of our properties.

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Eagle Ford Trend

In our operated leasehold acreage located in the Eagle Ford Trend, we have spud 7.0 gross/ 3.1 net wells in the first half of 2019 and expect to have them all completed by the end of 2019. We plan to spud and complete 3.0 gross/2.0 net additional wells in the latter half of 2019.

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 have been no significant changes to our critical accounting policies during the six months ended June 30, 2019.

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Results of Operations

Three Months Ended June 30, 2019, compared to the Three Months Ended June 30, 2018



	Three Months Ended June 30,
	2019			2018			Change
Sales volumes:
Oil (MBbl)	704			505			39	%
Natural gas (MMcf)	1,243			892			39	%
Natural gas liquids (MBbl)	245			151			62	%
Barrels of oil equivalent (MBOE)	1,156			805			44	%
Average Daily Production (Boepd)	12,699			8,845			44	%

Average prices:
Oil (per Bbl)	$	57.92		$	63.16		(8	)%
Natural gas (per Mcf)	$	0.10		$	2.00		(95	)%
Natural gas liquids (per Bbl)	$	14.90		$	22.92		(35	)%

Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl)	$	61.92		$	53.09		17	%
Natural gas ($/Mcf)	$	1.54		$	2.10		(27	)%
Natural gas liquids ($/Bbl)	$	14.90		$	22.92		(35	)%

(In thousands)
Oil revenues	$	40,767		31,903			28	%
Natural gas revenues	$	129		1,783			(93	)%
Natural gas liquids revenues	$	3,646		3,464			5	%

Lease operating expense	$	8,605		$	5,009		72	%
Severance taxes	$	2,109		$	1,824		16	%
Depreciation, depletion and amortization	$	14,197		$	10,812		31	%

General and administrative expense (excluding stock-based compensation)	$	4,767		$	5,213		(9	)%
Stock-based compensation	$	2,261		$	2,073		9	%
General and administrative expense	$	7,028		$	7,286		(4	)%

(Loss) gain on sale of oil and gas properties	$	(201	)	63			(419	)%
Interest expense, net	$	(1,677	)	$	(610	)	175	%

Unrealized gain (loss) on derivative contracts	$	4,902		$	(5,858	)	NM
Realized gain (loss) on derivative contracts	$	4,594		$	(4,992	)	NM
Gain (loss) on derivative contracts, net	$	9,496		$	(10,850	)	NM

Income tax (expense) benefit	$	(613	)	$	302		NM

NM – Not Meaningful

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Oil revenues

For the three months ended June 30, 2019, oil revenues increased by $8.9 million or 28% relative to the comparable period in 2018. Of the increase, $11.5 million was attributable to an increase in volume, partially offset by $2.6 million attributable to a decrease in our realized price. Our average realized price per Bbl decreased from $63.16 for the three months ended June 30, 2018 to $57.92 or 8% for the three months ended June 30, 2019. We had a net increase in the volume of oil sold of 199 MBbls or 39%, 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 three months ended June 30, 2019, natural gas revenues decreased by $1.7 million or 93% relative to the comparable period in 2018, primarily due to a drastic decrease in realized price in the Midland Basin. Our average realized price per Mcf decreased from $2.00 for the three months ended June 30, 2018 to $0.10 or 95% for the three months ended June 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. The total volume of natural gas produced and sold increased 351 MMcf or 39% primarily due to new wells brought online, partially offset by the impact of 2018 gas well divestitures.

Natural gas liquids revenues

For the three months ended June 30, 2019, natural gas liquids revenues increased by $0.2 million or 5% relative to the comparable period in 2018. Of the increase, $1.4 million was attributable to increased volume, partially offset by $1.2 million attributable to a decrease in our realized price. 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 large decreases in prices received. The volume of natural gas liquids produced and sold increased by 94 MBbls or 62%, 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 $3.6 million or 72% for the three months ended June 30, 2019 relative to the comparable period in 2018. The increase was primarily due to additional producing wells brought online, which drove a 44% increase in production volume; in addition to a $1.4 million increase driven by a greater number of workover projects as compared to the prior year quarter.

Severance taxes

Severance taxes for the three months ended June 30, 2019 increased $0.3 million or 16% as compared to the comparable period in 2018. The increase was primarily due to increased volume, partially 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.

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

DD&A increased for the three months ended June 30, 2019 by $3.4 million, or 31% 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 three months ended June 30, 2019 decreased by $0.3 million, or 4% relative to the comparable period in 2018 primarily due to lower legal fees, partially offset by an increase in non-cash stock-based compensation expense related to restricted stock units awarded to our executive officers on January 28, 2019.

Interest expense, net

Interest expense increased from $0.6 million for the three months ended June 30, 2018 to $1.7 million for the three months ended June 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.

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Gain (loss) on derivative contracts, net

For the three months ended June 30, 2019, we recorded a net gain on derivative contracts of $9.5 million, consisting of unrealized mark-to-market gains of $4.9 million and net realized gains on settlements of $4.6 million. For the three months ended June 30, 2018, we recorded a net loss on derivative contracts of $10.9 million, consisting of unrealized mark-to-market losses of $5.9 million and net realized losses on settlements of $5.0 million.

Income tax (expense) benefit

During the three months ended June 30, 2019, we recorded income tax expense of approximately $0.6 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, (2) no net income tax expense for Earthstone as the $1.3 million income tax expense resulting from its share of the distributable income 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 $0.3 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the three months ended June 30, 2019.

During the three months ended June 30, 2018, we recorded an income tax benefit of $0.3 million which included (1) a $0.5 million discrete income tax benefit related to refundable AMT tax credits resulting from the Tax Cuts and Jobs Act ("TCJA") and (2) a deferred income tax expense of $0.2 million related to the Texas Margin Tax.

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Six Months Ended June 30, 2019, compared to the Six Months Ended June 30, 2018



	Six Months Ended June 30,
	2019			2018			Change
Sales volumes:
Oil (MBbl)	1,382			1,051			31	%
Natural gas (MMcf)	2,070			1,936			7	%
Natural gas liquids (MBbl)	438			301			45	%
Barrels of oil equivalent (MBOE)	2,164			1,675			29	%
Average Daily Production (Boepd)	11,958			9,252			29	%

Average prices:
Oil (per Bbl)	$	55.17		$	63.11		(13	)%
Natural gas (per Mcf)	$	0.59		$	2.31		(74	)%
Natural gas liquids (per Bbl)	$	17.89		$	24.11		(26	)%

Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl)⁽¹⁾	$	60.88		$	54.14		12	%
Natural gas ($/Mcf)⁽¹⁾	$	1.58		$	2.39		(34	)%
Natural gas liquids ($/Bbl)	$	17.89		$	24.11		(26	)%

(In thousands)
Oil revenues	$	76,214		$	66,320		15	%
Natural gas revenues	$	1,223		$	4,467		(73	)%
Natural gas liquids revenues	$	7,833		$	7,258		8	%

Lease operating expense	$	15,272		$	9,666		58	%
Severance taxes	$	4,097		$	3,861		6	%
Depreciation, depletion and amortization	$	28,202		$	20,520		37	%

General and administrative expense (excluding stock-based compensation)	$	9,825		$	9,852		—	%
Stock-based compensation	$	4,473		$	4,013		11	%
General and administrative expense	$	14,298		$	13,865		3	%

(Loss) gain on sale of oil and gas properties	$	(326	)	$	512		(164	)%
Interest expense, net	$	(3,126	)	$	(1,223	)	156	%

Unrealized loss on derivative contracts	$	(48,354	)	$	(6,858	)	NM
Realized gain (loss) on derivative contracts	$	9,956		$	(9,267	)	NM
Loss on derivative contracts, net	$	(38,398	)	$	(16,125	)	NM

Income tax (expense) benefit	$	(153	)	$	53		NM

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

NM – Not Meaningful

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Oil revenues

For the six months ended June 30, 2019, oil revenues increased by $9.9 million or 15% relative to the comparable period in 2018. Of the increase, $18.2 million was attributable to an increase in volume, partially offset by $8.3 million attributable to a decrease in our realized price. Our average realized price per Bbl decreased from $63.11 for the six months ended June 30, 2018 to $55.17 or 13% for the six months ended June 30, 2019. We had a net increase in the volume of oil sold of 331 MBbls or 31%, 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 six months ended June 30, 2019, natural gas revenues decreased by $3.2 million or 73% 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 from $2.31 for the six months ended June 30, 2018 to $0.59 or 74% for the six months ended June 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 134 MMcf or 7% primarily due to new wells brought online, partially offset by the impact of 2018 gas well divestitures.

Natural gas liquids revenues

For the six months ended June 30, 2019, natural gas liquids revenues increased by $0.6 million or 8% relative to the comparable period in 2018. Of the increase, $2.4 million was attributable to increased volume, partially offset by $1.9 million attributable to a decrease in our realized price. 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 large decreases in prices received. The volume of natural gas liquids produced and sold increased by 137 MBbls or 45%, 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 $5.6 million or 58% for the six months ended June 30, 2019 relative to the comparable period in 2018. The increase was primarily due to additional producing wells brought online, which drove a 29% increase in production volume; in addition to a $2.4 million increase driven by a greater number of workover projects as compared to the prior year period.

Severance taxes

Severance taxes for the six months ended June 30, 2019 increased $0.2 million or 6% 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.

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

DD&A increased for the six months ended June 30, 2019 by $7.7 million, or 37% 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 six months ended June 30, 2019 increased by $0.4 million, or 3% relative to the comparable period in 2018. The increase was primarily due to non-cash stock-based compensation expense related to restricted stock units awarded to our executive officers on January 28, 2019.

Interest expense, net

Interest expense increased from $1.2 million for the six months ended June 30, 2018 to $3.1 million for the six months ended June 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.

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Loss on derivative contracts, net

For the six months ended June 30, 2019, we recorded a net loss on derivative contracts of $38.4 million, consisting of unrealized mark-to-market losses of $48.4 million, partially offset by net realized gains on settlements of $10.0 million. For the six months ended June 30, 2018, we recorded a net loss on derivative contracts of $16.1 million, consisting of unrealized mark-to-market losses of $6.8 million and net realized losses on settlements of $9.3 million.

Income tax (expense) benefit

During the six months ended June 30, 2019, we recorded income tax expense of approximately $0.2 million which included (1) income tax benefit for Lynden US of $0.4 million as a result of its share of the distributable loss from EEH, (2) no net income tax benefit for Earthstone as the $1.6 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 six months ended June 30, 2019.

During the six months ended June 30, 2018, the Company recorded a net income tax benefit of approximately $0.1 million which included (1) income tax expense for Lynden US of $0.2 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 $0.9 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation recorded against its deferred tax asset as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $0.2 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the six months ended June 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 June 30, 2019, we had approximately $5.8 million in cash and approximately $215 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 which $79.8 million has been spent through June 30, 2019. Our 2019 capital program assumes a 18-well program for our operated acreage 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 continue to outspend our cash flows provided by operating activities over at least the next 12 months from the date of this report based on current assumptions. However, we believe we will have sufficient liquidity with cash flows from operations and borrowings under the EEH Credit Agreement 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.

Working capital, defined herein as Total current assets less Total current liabilities as set forth in our Condensed Consolidated Balance Sheets, was a deficit of $35.3 million as of June 30, 2019 compared to a deficit of $18.3 million as of December 31, 2018. Our collection of receivables has historically been timely and losses associated with uncollectible receivables have historically not been significant. The increase in the working capital deficit is primarily the result of a net decrease in fair value of our derivative contracts expected to settle over the next 12 months partially offset by increased cash and receivables. We expect that changes in receivables and payables related to our pace 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.

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.

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Cash Flows from Operating Activities

Cash flows provided by operating activities for the six months ended June 30, 2019 were $55.3 million compared to $53.4 million for the six months ended June 30, 2018. The increase in operating cash flows from the prior year period was primarily due to use of cash from changes in payables and receivables related to our operation of our oil and gas properties partially offset by sources of cash from changes in cash settlements of derivative contracts.

Cash Flows from Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2019 and 2018 were $80.0 million and $68.4 million, respectively. The increase in cash flows used in investing activities was primarily due to increased drilling and completion activity as compared to the prior year period.

Cash Flows from Financing Activities

Cash flows provided by financing activities for the six months ended June 30, 2019 were $30.1 million, as compared to cash flows used in financing activities of $3.8 million during the six months ended June 30, 2018. The change was primarily due to higher net borrowings under the EEH Credit Agreement in the current year period which were used to fund our drilling and completion activities.

Capital Expenditures

Our 2019 capital budget assumes a one-rig operated program, with a temporary second rig currently deployed, 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 spent $79.8 million on a cash basis and incurred $73.8 million on an accrual basis during the first two quarters of 2019 (the difference of $6.0 million representing a decrease in accrued but unpaid capital expenditures from December 31, 2018 to June 30, 2019).

Our accrual basis capital expenditures for the three and six months ended June 30, 2019 were as follows (in thousands):



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Drilling and completions	$	23,971	$	66,445
Leasehold costs	7,154		7,350
Total capital expenditures	$	31,125	$	73,795

Credit Agreement

In May, 2017, Earthstone Energy Holdings, LLC (“EEH” or the “Borrower”), a subsidiary 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, as guarantors (the “Guarantors”), BOKF, NA dba Bank Of Texas, as Agent and Lead Arranger, Wells Fargo Bank, National Association, as Syndication Agent, and the lenders party thereto (the “Lenders”), entered into a credit agreement (as amended, modified or restated from time to time, the “EEH Credit Agreement”).

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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.

Hedging Activities

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



Period	Commodity	Volume (Bbls / MMBtu)	Price ($/Bbl / $/MMBtu)
Q3 - Q4 2019	Crude Oil	1,177,600	$65.64
Q1 - Q4 2020	Crude Oil	1,830,000	$63.80
Q1 - Q4 2021	Crude Oil	365,000	$55.53
Q3 - Q4 2019	Crude Oil Basis Swap(1)	1,012,000	$(5.29)
Q3 - Q4 2019	Crude Oil Basis Swap(2)	184,000	$4.50
Q1 - Q4 2020	Crude Oil Basis Swap(1)	1,830,000	$(2.14)
Q3 - Q4 2019	Natural Gas	1,564,000	$2.85
Q1 - Q4 2020	Natural Gas	2,562,000	$2.85
Q3 - Q4 2019	Natural Gas Basis Swap(3)	1,564,000	$(1.16)
Q1 - Q4 2020	Natural Gas Basis Swap(3)	2,562,000	$(1.07)


(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 and the WTI NYMEX.


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

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Subsequent to June 30, 2019, we entered into additional hedges consisting of Crude Oil Swaps on 731 MBbls at a price of $54.47/Bbl for 2020 and 2021, WTI Midland Argus Crude Basis Swaps on 366 MBbls at a price of $0.55/Bbl for 2020 and WTI Midland Argus Crude Basis Swaps on 730 MBbls at a price of $0.85/Bbl for 2021.

The following table sets forth our outstanding derivative contracts as of July 1, 2019 updated for contracts entered into through August 1, 2019. When aggregating multiple contracts, the weighted average contract price is disclosed.



Period	Commodity	Volume (Bbls / MMBtu)	Price ($/Bbl / $/MMBtu)
Q3 - Q4 2019	Crude Oil	1,177,600	$65.63
Q1 - Q4 2020	Crude Oil	2,196,000	$62.25
Q1 - Q4 2021	Crude Oil	730,000	$55.00
Q3 - Q4 2019	Crude Oil Basis Swap(1)	1,012,000	$(5.29)
Q3 - Q4 2019	Crude Oil Basis Swap(2)	184,000	$4.50
Q1 - Q4 2020	Crude Oil Basis Swap(1)	2,196,000	$(1.69)
Q1 - Q4 2021	Crude Oil Basis Swap(1)	730,000	$0.85
Q3 - Q4 2019	Natural Gas	1,564,000	$2.85
Q1 - Q4 2020	Natural Gas	2,562,000	$2.85
Q3 - Q4 2019	Natural Gas Basis Swap(3)	1,564,000	$(1.16)
Q1 - Q4 2020	Natural Gas Basis Swap(3)	2,562,000	$(1.07)


(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 and the WTI NYMEX.


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

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 Annual Report on Form 10-K other than those described in Note 12. 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

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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 June 30, 2019 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.

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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 June 30, 2019, 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. 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.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2018.

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 six months ended June 30, 2019.

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
April 2019	—	$	—	—	—
May 2019	—	—		—	—
June 2019	43,344	$	6.12	—	—


(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 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.

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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	XBRL Instance Document	X
101.SCH	XBRL Schema Document	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

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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:	August 6, 2019	By:	/s/ Tony Oviedo
			Tony Oviedo
			Executive Vice President – Accounting and Administration