Earthstone Energy (ESTE) 10-K 15 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Mar. 05, 2018	Jun. 30, 2017
Document And Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	ESTE
Entity Registrant Name	EARTHSTONE ENERGY INC
Entity Central Index Key	10,254
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 181,689,218
Class A Common Stock [Member]
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		27,828,773
Class B Common Stock [Member]
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		35,858,123

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash	$ 22,955	$ 10,200
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	14,978	13,998
Joint interest billings and other, net of allowance of $138 and $163 at December 31, 2017 and 2016, respectively	7,778	2,698
Derivative asset	184
Prepaid expenses and other current assets	1,178	446
Total current assets	47,073	27,342
Oil and gas properties, successful efforts method:
Proved properties	605,039	363,072
Unproved properties	275,025	51,723
Land	5,534
Total oil and gas properties	885,598	414,795
Accumulated depreciation, depletion and amortization	(118,028)	(145,393)
Net oil and gas properties	767,570	269,402
Other noncurrent assets:
Goodwill	17,620	17,620
Office and other equipment, net of accumulated depreciation of $2,093 and $1,600 at December 31, 2017 and 2016, respectively	947	1,479
Other noncurrent assets	1,207	669
TOTAL ASSETS	834,417	316,512
Current liabilities:
Accounts payable	33,472	11,927
Revenues and royalties payable	10,288	10,769
Accrued expenses	8,707	5,392
Derivative liability	11,805	4,595
Advances	4,587	4,542
Current portion of long-term debt		1,604
Total current liabilities	68,859	38,829
Noncurrent liabilities:
Long-term debt	25,000	12,693
Asset retirement obligation	2,354	6,013
Derivative liability	1,826	1,575
Deferred tax liability	10,515	15,776
Other noncurrent liabilities	131	169
Total noncurrent liabilities	39,826	36,226
Commitments and Contingencies (Note 15)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding
Common stock		23
Additional paid-in capital	503,932	454,202
Accumulated deficit	(224,822)	(212,308)
Treasury stock, no shares at December 31, 2017 and 15,357 shares at December 31, 2016		(460)
Total Earthstone Energy, Inc. equity	279,174	241,457
Noncontrolling interest	446,558
Total equity	725,732	241,457
TOTAL LIABILITIES AND EQUITY	834,417	$ 316,512
Class A Common Stock [Member]
Equity:
Common stock	28
Class B Common Stock [Member]
Equity:
Common stock	$ 36

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Joint interest billings and other, allowance	$ 138	$ 163
Office and other equipment, accumulated depreciation	$ 2,093	$ 1,600
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	0	100,000,000
Common stock, shares issued	0	22,289,177
Common stock, shares outstanding	0	22,273,820
Treasury stock, shares	0	15,357
Class A Common Stock [Member]
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	27,584,638	0
Common stock, shares outstanding	27,584,638	0
Class B Common Stock [Member]
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	50,000,000	50,000,000
Common stock, shares issued	36,052,169	0
Common stock, shares outstanding	36,052,169	0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES
Oil	$ 88,536	$ 34,358	$ 39,849
Natural gas	8,777	5,046	5,457
Natural gas liquids	10,765	2,865	2,158
Total revenues	108,078	42,269	47,464
OPERATING COSTS AND EXPENSES
Lease operating expense	19,658	15,067	15,422
Severance taxes	6,060	2,198	2,582
Rig idle and termination expense		5,059
Impairment expense	72,191	24,283	138,086
Depreciation, depletion and amortization	36,915	25,937	31,228
General and administrative expense	20,466	9,414	9,711
Stock-based compensation	6,601	3,301
Transaction costs	4,732	2,483	589
Accretion of asset retirement obligation	434	551	550
Exploration expense	1	5	142
Total operating costs and expenses	167,058	88,298	198,310
Gain on sale of oil and gas properties	9,105	8	1,617
Loss from operations	(49,875)	(46,021)	(149,229)
OTHER INCOME (EXPENSE)
Interest expense, net	(2,699)	(1,282)	(722)
Write-off of deferred financing costs	(526)
(Loss) gain on derivative contracts, net	(7,986)	(6,638)	6,431
Other (expense) income, net	(20)	(72)	423
Total other income (expense)	(11,231)	(7,992)	6,132
Loss before income taxes	(61,106)	(54,013)	(143,097)
Income tax benefit (expense)	16,373	(528)	26,442
Net loss	(44,733)	(54,541)	(116,655)
Less: Net loss attributable to noncontrolling interest	(32,219)
Net loss attributable to Earthstone Energy, Inc.	$ (12,514)	$ (54,541)	$ (116,655)
Net loss per common share attributable to Earthstone Energy, Inc.:
Basic and diluted	$ (0.53)	$ (2.92)	$ (8.43)
Weighted average common shares outstanding:
Basic and diluted	23,589,973	18,651,582	13,835,128

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Bold Contribution Agreement [Member]	Restricted Stock Units [Member]	Lynden Arrangement [Member]	Class A Common Stock [Member]	Class B Common Stock [Member]Bold Contribution Agreement [Member]	Common Stock [Member]	Common Stock [Member]Bold Contribution Agreement [Member]	Common Stock [Member]Restricted Stock Units [Member]	Common Stock [Member]Lynden Arrangement [Member]	Common Stock [Member]Class A Common Stock [Member]	Common Stock [Member]Class A Common Stock [Member]Bold Contribution Agreement [Member]	Common Stock [Member]Class A Common Stock [Member]Restricted Stock Units [Member]Bold Contribution Agreement [Member]	Common Stock [Member]Class B Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]Bold Contribution Agreement [Member]	Additional Paid-in Capital [Member]Restricted Stock Units [Member]	Additional Paid-in Capital [Member]Lynden Arrangement [Member]	Accumulated Deficit [Member]	Treasury Stock [Member]	Total Earthstone Energy, Inc. Stockholders' Equity [Member]	Total Earthstone Energy, Inc. Stockholders' Equity [Member]Bold Contribution Agreement [Member]	Total Earthstone Energy, Inc. Stockholders' Equity [Member]Restricted Stock Units [Member]	Total Earthstone Energy, Inc. Stockholders' Equity [Member]Lynden Arrangement [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]Bold Contribution Agreement [Member]
Beginning Balance, amount at Dec. 31, 2014	$ 316,528						$ 14								$ 358,086				$ (41,112)	$ (460)	$ 316,528
Beginning Balance, shares at Dec. 31, 2014							13,835,128
Net loss	(116,655)																		(116,655)		(116,655)
Ending Balance, amount at Dec. 31, 2015	199,873						$ 14								358,086				(157,767)	(460)	199,873
Ending Balance, shares at Dec. 31, 2015							13,835,128
Stock-based compensation expense	3,301														3,301						3,301
Common stock issued, net of offering costs	47,125						$ 5								47,120						47,125
Common stock issued, net of offering costs, shares							4,753,770
Shares issued and sold in connection with Arrangement				$ 45,699						$ 4								$ 45,695						$ 45,699
Shares issued and sold in connection with Arrangement, shares										3,700,279
Net loss	(54,541)																		(54,541)		(54,541)
Ending Balance, amount at Dec. 31, 2016	241,457						$ 23								454,202				(212,308)	(460)	241,457
Ending Balance, shares at Dec. 31, 2016							22,289,177
Stock-based compensation expense	6,601														6,601						6,601
Common stock issued, net of offering costs	39,438										$ 5				39,433						39,438
Common stock issued, net of offering costs, shares											4,500,000
Shares issued and sold in connection with Arrangement	36													$ 36							36
Shares issued and sold in connection with Arrangement, shares														36,070,828
Vesting of restricted stock units			$ 1														$ 1						$ 1
Vesting of restricted stock units, shares									382,804				259,355
Common stock exchanged in connection with Bold Contribution Agreement								$ (23)				$ 23
Common stock exchanged in connection with Bold Contribution Agreement, shares								(22,656,624)				22,656,624
Treasury shares converted to Class A Common Stock, shares							(15,357)				15,357
Closing of Bold Contribution Agreement		$ 491,879														$ 12,872						$ 12,872				$ 479,007
Closing of Bold Contribution Agreement, shares												150,000
Deferred tax consequences of Bold Contribution Agreement		$ (8,270)														$ (8,270)						$ (8,270)
Class A Common Stock retained by the Company in exchange for payment of recipient mandatory tax withholdings	(675)														(675)						(675)
Class A Common Stock retained by the Company in exchange for payment of recipient mandatory tax withholdings, shares											61,055
Cancellation of treasury shares															(460)					$ 460
Cancellation of treasury shares, shares											(76,412)
Class B Common Stock converted to Class A Common Stock					$ (230)										230						230				$ (230)
Class B Common Stock converted to Class A Common Stock, shares						(18,659)					18,659			(18,659)
Net loss	(44,733)																		(12,514)		(12,514)				(32,219)
Ending Balance, amount at Dec. 31, 2017	$ 725,732										$ 28			$ 36	$ 503,932				$ (224,822)		$ 279,174				$ 446,558
Ending Balance, shares at Dec. 31, 2017											27,584,638			36,052,169

Consolidated Statements of Equ6

Consolidated Statements of Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement Of Stockholders Equity [Abstract]
Common stock issued, offering costs	$ 2.2	$ 2.7

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net loss	$ (44,733,000)	$ (54,541,000)	$ (116,655,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Impairment of proved and unproved oil and gas properties	72,191,000	24,283,000	138,086,000
Depreciation, depletion and amortization	36,915,000	25,937,000	31,228,000
Accretion of asset retirement obligations	434,000	551,000	550,000
Impairment of goodwill	0	17,532,000	1,547,000
Gain on sale of oil and gas properties	(9,105,000)	(8,000)	(1,617,000)
Settlement of asset retirement obligations	(9,000)	(15,000)	(108,000)
Rig idle and termination expense		5,059,000
Total loss (gain) on derivative contracts, net	7,986,000	6,638,000	(6,431,000)
Operating portion of net cash (paid) received in settlement of derivative contracts	(708,000)	3,225,000	6,306,000
Stock-based compensation	6,601,000	3,301,000
Deferred income taxes	(16,388,000)	528,000	(26,533,000)
Write-off of deferred financing costs	526,000
Amortization of deferred financing costs	257,000	298,000	264,000
Changes in assets and liabilities:
Decrease in accounts receivable	444,000	3,807,000	9,246,000
(Increase) decrease in prepaid expenses and other current assets	(335,000)	511,000	779,000
Decrease in accounts payable and accrued expenses	(282,000)	(9,151,000)	(30,887,000)
(Decrease) increase in revenues and royalties payable	(2,888,000)	2,194,000	(8,739,000)
Increase (decrease) in advances	45,000	(10,905,000)	(5,929,000)
Net cash provided by (used in) operating activities	50,951,000	1,712,000	(10,440,000)
Cash flows from investing activities:
Acquisition of oil and gas properties	(55,609,000)		(8,706,000)
Additions to oil and gas properties	(65,262,000)	(28,417,000)	(61,060,000)
Additions to office and other equipment	(167,000)	(117,000)	(378,000)
Proceeds from sale of oil and gas properties	34,735,000		3,441,000
Proceeds from sale of land			101,000
Net cash used in investing activities	(86,303,000)	(59,868,000)	(66,602,000)
Cash flows from financing activities:
Proceeds from borrowings	85,000,000	36,597,000
Repayments of borrowings	(74,298,000)	(38,549,000)
Cash paid related to the exchange and cancelation of Common Stock	(675,000)
Deferred financing costs	(1,358,000)	(81,000)	(141,000)
Issuance of Class A Common Stock and Common Stock, net of offering costs of $2.2 million and $2.7 million, respectively	39,438,000	47,125,000
Net cash provided by (used in) financing activities	48,107,000	45,092,000	(141,000)
Net increase (decrease) in cash and cash equivalents	12,755,000	(13,064,000)	(77,183,000)
Cash at beginning of period	10,200,000	23,264,000	100,447,000
Cash at end of period	22,955,000	10,200,000	23,264,000
Cash paid for:
Interest	2,495,000	961,000	415,000
Non-cash investing and financing activities:
Accrued capital expenditures	19,883,000	2,374,000	7,665,000
Asset retirement obligations	(42,000)	152,000	150,000
Promissory Note		5,059,000
Acquisition of oil and gas properties			1,991,000
Bold Contribution Agreement [Member] | Class B Common Stock [Member]
Non-cash investing and financing activities:
Common stock issued	489,842,000
Bold Contribution Agreement [Member] | Class A Common Stock [Member]
Non-cash investing and financing activities:
Common stock issued	2,037,000
Lynden Arrangement [Member]
Cash flows from investing activities:
Business acquisition, net of cash acquired		(31,334,000)
Non-cash investing and financing activities:
Common stock issued		45,699,000
Proved And Unproved Property [Member]
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Impairment of proved and unproved oil and gas properties	$ 72,191,000	$ 6,751,000	$ 136,539,000

Consolidated Statements of Cas8

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016
Statement Of Cash Flows [Abstract]
Issuance of common stock, offering costs	$ 2.7	$ 2.2	$ 2.7

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. – Organization and Basis of Presentation 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 up-stream 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 Consolidated Financial Statements representing the economic interests of EEH's members other than Earthstone and Lynden US. Certain prior period amounts have been reclassified to conform to current period presentation within the Consolidated Financial Statements. Prior period Re-engineering and workovers in the Consolidated Statements of Operations have been reclassified from its own line item and included in Lease operating expenses, within Operating Costs and Expenses, to conform to current period presentation. This reclassification had no effect on Loss from operations or any other subtotal in the Consolidated Statements of Operations. Bold Contribution Agreement On May 9, 2017, Earthstone completed a contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 (the “Bold Contribution Agreement”), The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes – Class A common stock, $0.001 par value per share (the “Class A Common Stock”), and Class B common stock, $0.001 par value per share (the “Class B Common Stock”), and all of Earthstone’s existing outstanding common stock, $0.001 par value per share (the “Common Stock”), was recapitalized on a one-for-one basis for Class A Common Stock (the “Recapitalization”); (ii) Earthstone transferred all of its membership interests in Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC and Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale of Class B Common Stock to Bold Holdings (collectively, the “Earthstone Assets”) to EEH, in exchange for 16,791,296 membership units of EEH (the “EEH Units”); (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH Units and purchased 36,070,828 shares of Class B Common Stock issued by Earthstone for $36,071; and (v) Earthstone granted an aggregate of 150,000 fully vested shares of Class A Common Stock under Earthstone’s 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock. Upon closing of the Bold Transaction on May 9, 2017, Bold Holdings owned approximately 61.4% of the outstanding shares of Class A Common Stock, on a fully diluted, as converted basis. The EEH Units and the shares of Class B Common Stock issued to Bold Holdings were not registered under the Securities Act of 1933, as amended (the “Securities Act”), but were issued by EEH and Earthstone in reliance on the exemption provided under Section 4(a)(2) of the Securities Act. On May 9, 2017, the closing sale price of the Class A Common Stock was $13.58 per share. On May 10, 2017, the Class A Common Stock was uplisted from the NYSE American, LLC (formerly the NYSE MKT) (the “NYSE American”) to the New York Stock Exchange (the “NYSE”) where it is listed under the symbol “ESTE.” On May 9, 2017, in connection with the closing of the Bold Transaction, Earthstone, EnCap Investments L.P. (“EnCap”), Oak Valley Resources, LLC (“OVR”), and Bold Holdings entered into a voting agreement (the “Voting Agreement”), pursuant to which EnCap, OVR, and Bold Holdings agreed not to vote any shares of Class A Common Stock or Class B Common Stock held by them in favor of any action, or take any action that would in any way alter the composition of the board of directors of Earthstone (the “Board”) from its composition immediately following the closing of the Bold Transaction as long as the Voting Agreement is in effect. The Voting Agreement terminates on the earlier of (i) the fifth anniversary of the closing date of the Bold Contribution Agreement and (ii) the date upon which EnCap, OVR and Bold Holdings collectively own, of record and beneficially, less than 20% of Earthstone’s outstanding voting stock. Pursuant to the terms of the Bold Contribution Agreement, at the closing of the Bold Transaction, Earthstone, Bold Holdings, and the unitholders of Bold Holdings entered into a registration rights agreement (the “Registration Rights Agreement”) relating to the shares of Class A Common Stock issuable upon the exchange of the EEH Units and Class B Common Stock held by Bold Holdings or its unitholders. In accordance with the Registration Rights Agreement, Earthstone filed a registration statement (the “Registration Statement”) with the Securities and Exchange Commission (the “SEC”) to permit the public resale of the shares of Class A Common Stock issued by Earthstone to Bold Holdings or its unitholders in connection with the exchange of Class B Common Stock and EEH Units in accordance with the terms of the First Amended and Restated Limited Liability Company Agreement of EEH (the “EEH LLC Agreement”). On October 18, 2017, the Registration Statement was declared effective by the SEC. The Bold Transaction was recorded in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, and is consolidated in these financial statements in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of net income (loss), as well as a noncontrolling interest component within equity, including changes to additional paid-in capital to reflect the noncontrolling interest within equity in the Consolidated Balance Sheet as of December 31, 2017 at the noncontrolling interest’s respective membership interest in EEH.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. – Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation. Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods then ended. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of our estimates. All reserve data included in these Consolidated Financial Statements are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered. Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, goodwill, asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) Accounts Receivable Accounts receivable include amounts due from crude oil, natural gas, and natural gas liquids purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and natural gas liquids sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability. Allowance for uncollectible accounts receivable was $0.1 million at and $0.2 million at December 31, 2017 and 2016, respectively. Derivative Instruments The Company utilizes derivative instruments in order to manage exposure to commodity price risk associated with future oil and natural gas production. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are mark-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations. Oil and Natural Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties as prescribed by the SEC. For more information see Note 6. Oil and Natural Gas Properties . 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 carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. There were no impairments to Goodwill recorded in the year ended December 31, 2017. During the years ended December 31, 2016 and 2015, impairments to Goodwill of $17.5 million and $1.5 million, respectively, were recorded. For further discussion, see Note 7. Goodwill Noncontrolling Interest Noncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2017, as well as an adjustment to Net loss in the Consolidated Statement of Operations for the year ended December 31, 2017. As of December 31, 2017, Earthstone and Lynden US owned a 43.3% membership interest in EEH while Bold Holdings, the noncontrolling third party, owned the remaining 56.7%. See further discussion in Note 8. Noncontrolling Interest Segment Reporting Operating segments are defined under FASB ASC Topic 280, Segment Reporting, as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas exploration and production. We consider drilling rig services ancillary to our oil and natural gas exploration and producing activities and manage these services to support such activities. Asset Retirement Obligations Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For further discussion, see Note 13. Asset Retirement Obligations Business Combinations The Company accounts for the acquisition of oil and gas properties not commonly controlled based on the requirements of FASB ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved developed oil and gas properties as business combinations. Revenue Recognition Oil, natural gas, and natural gas liquids revenues represent income from the production and delivery of oil, natural gas, and natural gas liquids, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has been transferred, and collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. The Company had no significant gas imbalances as of December 31, 2017, 2016, or 2015. Concentration of Credit Risk Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms. The purchasers of the Company’s oil, natural gas, and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2017, three purchasers accounted for 18%, 14% and 14%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In 2016, two purchasers accounted for 41% and 19%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In 2015, one purchaser accounted for 62% of the Company’s oil, natural gas, and natural gas liquids revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2017, 2016, and 2015. Additionally, at December 31, 2017, three purchasers accounted for 20%, 13% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. At December 31, 2016, two purchasers accounted for 28% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2017 and 2016. The Company holds working interests in oil and natural gas properties for which a third party serves as operator. The operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In 2017, 2016 and 2015, one operator distributed 10%, 19% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids revenues. No other operator accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2017, 2016, and 2015. The derivative instruments of the Company are with a small number of counterparties and, from time-to-time, may represent material assets in the Consolidated Balance Sheets. At December 31, 2017 and 2016, the Company had no derivative contracts that were in a material asset position. The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage. Income Taxes The Company is a U.S. company operating primarily in Texas, as of December 31, 2017, as well as one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which its operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, the Company is required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as its operations are conducted in different taxing jurisdictions. Following the closing of the Bold Transaction, the Company continues to record an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from Earthstone’s acquisition of Lynden Corp in May 2016 (the “Lynden Arrangement”) that includes 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. Following the Bold Transaction, Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. 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. The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in the Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2017 and 2016, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets. The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management and they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2017, 2016 or 2015. On December 22, 2017, the United States enacted tax reform legislation commonly known as the Tax Cuts and Jobs Act (the “TCJA”), resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes the federal corporate income tax rate reduction The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change . Recently Issued Accounting Standards Accounting for the Tax Cuts and Jobs Act – In December 2017, the SEC Staff issued Staff Accounting Bulletin No. 118, (“SAB 118”), to supplement the accounting requirements of FASB ASC Topic 740, (ASC Topic 740), as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. In the fourth quarter of 2017, the Company remeasured its deferred taxes at 21%, in accordance with the TCJA and GAAP. For further details, see Note 16. Income Taxes Revenue Recognition - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers, which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. This new revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The new standard is now effective prospectively for reporting periods beginning on or after December 15, 2017. The Company has completed its evaluation of the new standard and will adopt the new standard, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements. The Company has elected to use the modified retrospective method for adoption and has updated its related internal control documentation, processes and controls to conform to the new standard. Leases – In February 2016, the FASB issued updated guidance on accounting for leases. The update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. Similar to current guidance, the update continues to differentiate between finance leases and operating leases; however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The standards update is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2019. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Consolidated Financial Statements. Statement of Cash Flows – In August 2016, the FASB issued updated guidance that clarifies how certain cash receipts and cash payments are presented in the statement of cash flows. This update provides guidance on eight specific cash flow issues. The standards update is effective for interim and annual periods beginning after December 15, 2017, and should be applied retrospectively to all periods presented. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Statements of Cash Flows. Business Combinations – In January 2017, the FASB issued updated guidance that clarifies the definition of a business, which amends the guidance used in evaluating whether a set of acquired assets and activities represents a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not considered a business. As a result, acquisition fees and expenses will be capitalized to the cost basis of the property acquired, and the tangible and intangible components acquired will be recorded based on their relative fair values as of the acquisition date. The standard is effective for all public business entities for annual periods beginning after December 15, 2017. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements. 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 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, if any, on its Consolidated Financial Statements. Compensation – Stock Compensation – In May 2017, the FASB issued updated guidance that provides clarity about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures The Company accounts for its acquisitions that qualify as business combinations, under the acquisition method of accounting in accordance with FASB ASC Topic 805, Business Combinations Bold Transaction On May 9, 2017, Earthstone completed the Bold Transaction described in Note 1. Organization and Basis of Presentation . An allocation of the purchase price was prepared using, among other things, a reserve report prepared by qualified reserve engineers and priced as of the acquisition date. The following allocation is still preliminary with respect to final tax amounts and certain accruals and includes the use of estimates based on information that was available to management at the time these Consolidated Financial Statements were prepared. The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed ( in thousands, except share and share price amounts Consideration: Shares of Class A Common Stock issued pursuant to the Bold Contribution Agreement to certain employees of Bold 150,000 EEH Units issued to Bold Holdings 36,070,828 Total equity interest issued in the Bold Transaction 36,220,828 Closing per share price of Class A Common Stock as of May 9, 2017 $ 13.58 Total consideration transferred (1) (2) $ 491,879 Fair value of assets acquired: Cash and cash equivalents $ 2,355 Other current assets 10,078 Oil and gas properties (3) 557,704 Amount attributable to assets acquired $ 570,137 Fair value of liabilities assumed: Long-term debt (4) $ 58,000 Current liabilities 17,042 Deferred tax liability 2,857 Noncurrent asset retirement obligations 359 Amount attributable to liabilities assumed $ 78,258 (1) Consideration included 150,000 shares of Class A Common Stock recorded above based upon its fair value which was determined using the closing price of $13.58 per share on May 9, 2017. (2) Consideration was 36,070,828 EEH Units. Additionally, Bold Holdings purchased 36,070,828 shares of Class B Common Stock for $36,071. Each EEH Unit, together with one share of Class B Common Stock, is convertible into one share of Class A Common Stock. The fair value of the consideration was determined using the closing price of the Company’s Class A Common Stock of $13.58 per share on May 9, 2017. (3) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projections of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 3. Fair Value Measurements (4) Concurrent with the closing of the Bold Transaction, EEH repaid Bold’s outstanding borrowings of $58.0 million under its credit agreement. The following unaudited supplemental pro forma condensed results of operations present consolidated information as though the Bold Transaction and the Bakken Sale (discussed below) had been completed as of January 1, 2016. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for Bold and Earthstone and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired and (ii) to eliminate non-recurring transaction costs directly related to the Bold Transaction that do not have a continuing impact on the Company’s operating results. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information ( in thousands, except per share amounts Years ended December 31, 2017 2016 (Unaudited) Revenue $ 126,839 $ 54,436 Loss before taxes $ (44,461 ) $ (40,564 ) Net loss $ (35,617 ) $ (41,092 ) Less: Net loss attributable to noncontrolling interest $ (22,005 ) $ (27,012 ) Net loss attributable to Earthstone Energy, Inc. $ (13,612 ) $ (14,080 ) Pro forma net loss per common share attributable to Earthstone Energy, Inc.: Basic and Diluted $ (0.57 ) $ (0.75 ) The Company has included in its Consolidated Statements of Operations, revenues of $50.2 million and direct operating expenses of $23.8 million for the period from May 9, 2017 to December 31, 2017 related to the properties acquired in the Bold Transaction. Divestitures On December 20, 2017, the Company sold all of its oil and natural gas leases, oil and natural gas wells and associated assets located in the Williston Basin in North Dakota (the “Bakken Sale”) for a net cash consideration of The sale resulted in a net gain of approximately $3.0 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations. The effective date of the sale was December 1, 2017. For the year ended December 31, 2017, the Company sold certain non-core properties for a total cash consideration of approximately $7.5 million, while eliminating approximately $4.0 million of future abandonment obligations. The sales resulted in a net gain of approximately $6.1 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations. In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes, for cash consideration of approximately $3.4 million. The sale resulted in a net gain of $1.6 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations. The effective date of the transaction was March 1, 2015.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 4. Fair Value Measurements FASB ASC Topic 820, The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 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 year ended December 31, 2017. 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 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) December 31, 2017 Level 1 Level 2 Level 3 Total Financial assets Derivative asset- current $ — $ 184 $ — $ 184 Total financial assets $ — $ 184 $ — $ 184 Financial liabilities Derivative liability - current $ — $ 11,805 $ — $ 11,805 Derivative liability - noncurrent — 1,826 — 1,826 Total financial liabilities $ — $ 13,631 $ — $ 13,631 December 31, 2016 Financial liabilities Derivative liability - current $ — $ 4,595 $ — $ 4,595 Derivative liability - noncurrent — 1,575 — 1,575 Total financial liabilities $ — $ 6,170 $ — $ 6,170 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 natural 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. See Note 6. Oil and Natural Gas Properties. 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. See Note 7. Goodwill Business Combinations The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 3 Acquisitions and Divestitures Asset Retirement Obligations The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. See Note 13 Asset Retirement Obligations

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Note 5. Derivative Financial Instruments In connection with the closing of the Bold Transaction on May 9, 2017, all oil and natural gas derivative contracts were novated to EEH. 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 swaps and basis swaps 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, 2019. 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 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 Consolidated Balance Sheets and 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. The following table sets forth the Company’s outstanding derivative contracts at December 31, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed. Period Commodity Volume (Bbl s Price ($/Bbl / $/MMBtu) 2018 Crude Oil Swap 1,483,250 $ 51.38 2018 Crude Oil Basis Swap (1) 602,250 $ (0.15 ) 2019 Crude Oil Swap 547,500 $ 52.32 2018 Natural Gas Swap 810,000 $ 3.066 (1) The basis differential price is between Midland – West Texas Intermediate (“WTI”) and the NYMEX – WTI In January 2018, the Company entered into additional fixed price oil and natural gas swap agreements, hedging an additional 365,000 Bbls of 2019 oil production at a price of $58.38/Bbl and 1,552,000 MMBtu of 2018 natural gas production at a price of $2.96/MMBtu. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets (in thousands) December 31, 2017 December 31, 2016 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 Derivative asset - current $ 184 $ — $ 184 $ — $ — $ — Commodity contracts Derivative liability - current $ 11,805 $ — $ 11,805 $ 4,595 $ — $ 4,595 Commodity contracts Derivative liability - noncurrent $ 1,826 $ — $ 1,826 $ 1,575 $ — $ 1,575 The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Company’s Consolidated Statements of Operations (in thousands) Years Ended December 31, 2017 2016 2015 Derivatives not designated as hedging contracts under ASC Topic 815 Statement of Operations Location Total (loss) gain on commodity contracts (Loss) gain on derivative contracts, net $ (7,278 ) $ (9,863 ) $ 125 Cash settlements on commodity contracts (Loss) gain on derivative contracts, net (708 ) 3,225 6,306 (Loss) gain on commodity contracts, net $ (7,986 ) $ (6,638 ) $ 6,431

Oil and Natural Gas Properties

Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Oil and Natural Gas Properties	Note 6. 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. 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 operating income (loss) in the 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. Depletion expense for oil and natural gas producing property and related equipment was $36.4 million, $25.4 million, and $30.7 million, for the years ended December 31, 2017, 2016, and 2015, respectively. Proved 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 natural 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 as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and natural 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 and depleted on a units-of-production basis. 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, our geologists' evaluation of the property, and the remaining months in the lease term for the property. The Company had the following non-cash asset impairment charges to its oil and natural gas properties for the years ended December 31, 2017, 2016 and 2015 ( in thousands Years Ended December 31, 2017 2016 2015 Proved property $ 63,131 $ 2,873 $ 93,984 Unproved property 9,060 3,878 42,555 Total $ 72,191 $ 6,751 $ 136,539 Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, 2017 and 2016, were $148.2 million and $162.7 million, respectively.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill	Note 7. 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 carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. The Company did not have any non-cash impairment charges to its goodwill for the year ended December 31, 2017. The Company had the following non-cash impairment charges to its goodwill for the years ended December 31, 2016 and 2015 ( in thousands Years Ended December 31, 2016 2015 Impairment expense - goodwill $ 17,532 $ 1,547 Accumulated impairments to Goodwill as of December 31, 2017 and 2016, were $19.1 million.

Noncontrolling Interest

Noncontrolling Interest	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
Noncontrolling Interest	Note 8. Noncontrolling Interest As a result of the Bold Transaction, Earthstone became the sole managing member of, and has a controlling interest in, EEH. As the sole managing member of EEH, Earthstone operates and controls all of the business and affairs of EEH and its subsidiaries. Immediately following the Bold Transaction, Earthstone and Lynden US owned a 38.6% membership interest in EEH while Bold Holdings owned the remaining 61.4%. The Bold Transaction was recorded in accordance with FASB ASC Topic 805, Business Combinations, and is consolidated in these financial statements in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of net income (loss), as well as a noncontrolling interest component within equity, including changes to Additional paid-in capital to reflect the noncontrolling interest within equity in the Consolidated Balance Sheet as of December 31, 2017 at the noncontrolling interest’s respective membership interest in EEH. A reconciliation of the equity attributable to the noncontrolling interest as of May 9, 2017 is as follows ( in thousands Total considerations transferred (1) $ 491,879 Change to additional paid-in capital to reflect the noncontrolling interest within equity at their membership interest (12,872 ) Portion of equity attributable to noncontrolling interest (2) $ 479,007 (1) See Note 3. Acquisitions and Divestitures (2) Represents 61.4% of total equity attributable to EEH as of May 9, 2017. Earthstone consolidates the financial results of EEH and its subsidiaries, and records a noncontrolling interest for the economic interest in Earthstone held by the members of EEH other than Earthstone and Lynden US. Net loss attributable to noncontrolling interest in the Consolidated Statements of Operations for the year ended December 31, 2017 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 Consolidated Balance Sheet as of December 31, 2017 represents the portion of net assets of the Company attributable to the members of EEH other than Earthstone and Lynden US. The following table presents the changes in noncontrolling interest for the year ended December 31, 2017: EEH Units Held By Earthstone and Lynden US % EEH Units Held By Others % Total EEH Units Outstanding As of December 31, 2016 — — — — — May 9, 2017 - Bold Transaction 22,656,624 38.6 % 36,070,828 61.4 % 58,727,452 EEH Units issued in connection with Class A Common Stock issued in connection with the Bold Transaction 150,000 — 150,000 EEH Units issued in connection with the vesting of restricted stock units and issuance of Class A Common Stock 259,355 — 259,355 EEH Units issued in connection with Class A Common Stock offering 4,500,000 — 4,500,000 EEH Units and Class B Common Stock converted to Class A Common Stock 18,659 (18,659 ) - As of December 31, 2017 27,584,638 43.3 % 36,052,169 56.7 % 63,636,807 The following table summarizes the activity for the equity attributable to the noncontrolling interest for the year ended December 31, 2017 ( in thousands 2017 As of December 31, 2016 $ — Noncontrolling interest recorded within equity in connection with the closing of the Bold Transaction 479,007 EEH Units and Class B Common Stock converted to Class A Common Stock (230 ) Net loss attributable to noncontrolling interest (32,219 ) As of December 31, 2017 $ 446,558

Net Loss Per Common Share

Net Loss Per Common Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Net Loss Per Common Share	Note 9. Net Loss Per Common Share Net loss per common share—basic is calculated by dividing Net loss A reconciliation of Net loss per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2017 2016 2015 Net loss attributable to Earthstone Energy, Inc. $ (12,514 ) $ (54,541 ) $ (116,655 ) Net loss per common share attributable to Earthstone Energy, Inc.: Basic $ (0.53 ) $ (2.92 ) $ (8.43 ) Diluted $ (0.53 ) $ (2.92 ) $ (8.43 ) Weighted average common shares outstanding Basic 23,589,973 18,651,582 13,835,128 Add potentially dilutive securities: Unvested restricted stock units — — — Diluted weighted average common shares outstanding 23,589,973 18,651,582 13,835,128 Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and Net loss attributable to noncontrolling interest of $32.2 million would be added back to Net loss attributable to Earthstone Energy, Inc., having no dilutive effect on Net loss per common share attributable to Earthstone Energy, Inc.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Common Stock	Note 10. Common Stock On May 9, 2017, and in connection with the completion of the Bold Transaction, Earthstone recapitalized its Common Stock into two classes, as described in Note 1. Organization and Basis of Presentation Class A Common Stock At December 31, 2017, there were 27,584,638 shares of Class A Common Stock issued and outstanding. On July 1, 2017, Earthstone retired and returned the 15,357 shares of treasury stock to authorized but unissued shares of Class A Common Stock. During the period January 1, 2017 through May 8, 2017, the Company issued 382,804 shares of Common Stock as a result of the vesting and settlement of restricted stock units under the 2014 Plan. During the period May 9, 2017 through December 31, 2017, the Company issued 320,410 shares of Class A Common Stock as a result of the vesting and settlement of restricted stock units under the 2014 Plan, of which 61,055 shares of Class A Common Stock were withheld by the Company in exchange for payment of income tax withholdings. Additionally, on May 9, 2017, under the Bold Contribution Agreement, Earthstone issued 150,000 shares of Class A Common Stock valued at approximately $2.0 million on that date. For additional information, see Note 3. Acquisitions and Divestitures Class A Common Stock Offering In October 2017, Earthstone completed a public offering of 4,500,000 shares of Class A Common Stock, at an issue price of $9.25 per share. Earthstone received net proceeds from this offering of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.2 million. The net proceeds from the offering were used to repay outstanding indebtedness under the EEH Credit Agreement, as described in Note 12. Long-Term Debt Class B Common Stock At December 31, 2017, there were 36,052,169 shares of Class B Common Stock issued and outstanding. On May 9, 2017, in connection with Earthstone’s completion of the Bold Transaction, Earthstone issued 36,070,828 shares of Class B Common Stock in exchange for $36 thousand. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock. Earthstone did not have any Class B Common Stock issued at December 31, 2016. For additional information, see Note 3. Acquisitions and Divestitures Common Stock During the year ended December 31, 2016, there were the following changes to the Common Stock: • On May 18, 2016, the Company acquired Lynden Corp in an all-stock transaction issuing 3,700,279 shares of Common Stock, valued at $45.7 million on that date, to the holders of the common stock of Lynden Corp. • In June 2016, the Company completed a public offering of 4,753,770 shares of Common Stock at an issue price of $10.50 per share. The Company received net proceeds from this offering of $47.1 million, after deducting underwriters’ fees and offering expenses of $2.7 million. During the year ended December 31, 2015, there were no changes to the Common Stock.

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock Based Compensation	The 2014 Plan allows, among other things, for the grant of restricted stock units (“RSUs”). On May 9, 2017, and in connection with the completion of the Bold Contribution Agreement, and upon approval by the stockholders of Earthstone, the 2014 Plan was amended to increase the number of shares of Class A Common Stock authorized to be issued under the 2014 Plan by 4.3 million shares, to a total of 5.8 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 Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting and is net of forfeitures, as incurred. The table below summarizes unvested RSU activity for the year ended December 31, 2017: Shares Weighted-Average Grant Date Fair Value Unvested RSUs at December 31, 2016 781,500 $ 12.53 Granted 949,000 $ 9.80 Forfeited (58,041 ) $ 12.98 Vested (703,214 ) $ 12.44 Unvested RSUs at December 31, 2017 969,245 $ 9.89 During the year ended December 2017, Earthstone granted 910,000 RSUs to employees and 39,000 RSUs to certain members of the Board with vesting periods varying from 12 months to 36 months. The total grant date fair value of the RSUs granted during the years 2017 and 2016 were $9.8 million and $9.3 million, respectively, with a weighted average grant fair value per share of $9.80 and $12.53, respectively. There were no RSUs granted during 2015. The total vesting date fair value of the RSUs that vested during 2017 was $8.3 million. There were no RSUs that vested during the years 2016 and 2015. As of December 31, 2017, there was approximately $8.4 million of total unrecognized stock-based compensation expense related to unvested RSUs, which will be amortized over the remaining vesting periods. The weighted average remaining vesting period of the unrecognized compensation expense is 0.91 years. Stock-based compensation expense for the years ended December 31, 2017 and 2016 was $6.6 million and $3.3 million, respectively. There was no stock-based compensation expense for the year ended December 31, 2015. Stock-based compensation expense is recorded in the Consolidated Statements of Operations with a corresponding increase in Additional paid-in capital within the Consolidated Balance Sheet.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Note 12. Long Credit Agreement On May 9, 2017, in connection with the closing of the Bold Transaction, the Company exited its credit agreement dated December 19, 2014, by and among Earthstone, OVR Operating, LLC, EF Non-OP, LLC, Sabine River Energy, LLC, Basic Petroleum Services, Inc., BOKF, NA dba Bank of Texas, and the lenders party thereto (as amended, modified or restated from time to time, the “ESTE Credit Agreement”). At that time, all outstanding borrowings of $10.0 million under the ESTE Credit Agreement were repaid and $0.5 million of remaining unamortized deferred financing costs were expensed and included in Write-off of deferred financing costs in the Consolidated Statements of Operations. On May 9, 2017, EEH (the “Borrower”), Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden Op, Bold, Bold Operating, LLC (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 (the “EEH Credit Agreement”). The borrowing base under the EEH Credit Agreement is currently $185.0 million, and is subject to redetermination on or about November 1st and May 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 2.25% to 3.25% or (b) the prime lending rate of Bank of Texas plus 1.25% to 2.25%, 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 0.50% per year to the Lenders in respect of the unutilized commitments thereunder, as well as certain other customary fees. The EEH Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and make distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio 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 December 31, 2017, EEH was in compliance with all covenants under the EEH Credit Agreement. As of December 31, 2017, the Company had a $185.0 million borrowing base under the EEH Credit Agreement, of which $25.0 million was outstanding, bearing an annual interest rate of 3.7611%, resulting in an additional $160.0 million of borrowing base availability under the EEH Credit Agreement. Promissory Note In July 2016, Earthstone issued a $5.1 million unsecured promissory note (the “Note”) to a drilling rig contractor in settlement of rig idle charges and the termination amount of the contract. These expenses which were incurred from late January 2016 through December 31, 2016 and were recorded in Rig idle and termination expense in the Consolidated Statements of Operations for the year ended December 31, 2016. The Note was assigned to EEH in connection with the closing of the Bold Transaction. In December 2017, the remaining balance of the Note was paid in full. The following table below summarizes long term debt ( in thousands December 31, 2017 2016 Credit Agreement $ 25,000 $ 10,000 Promissory note — 4,297 Total debt 25,000 14,297 Less: Current portion of long-term debt — (1,604 ) Long-term debt $ 25,000 $ 12,693 For the year ended December 31, 2017, the Company had borrowings of $85.0 million and $74.3 million in repayments of borrowings. The borrowings included $58.0 million related to the repayments of all outstanding borrowings under Bold’s credit agreement which were assumed by EEH in connection with the closing of the Bold Transaction. The repayments primarily included $35.0 million of the proceeds received from the Class A Common Stock offering in October 2017 and $25.0 million of the proceeds received from the Bakken Sale in December 2017. As stated above, in December 2017, the remaining balance of the Note was paid in full. For the years ended December 31, 2017, 2016 and 2015, interest on all outstanding debt averaged 4.26%, 4.03% and 1.68% per annum, respectively, of which excluded commitment fees of $0.3 million for each period ended and amortization of deferred financing costs of $0.3 million for each period ended, respectively. The Company capitalized $1.4 million, $0.1 million and $0.1 million, respectively, of costs associated with the credit agreements for the years ended December 31, 2017, 2016 and 2015. These capitalized costs are included in Other noncurrent assets in the 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.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 13. Asset Retirement Obligations The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural 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 years ended December 31, 2017 and 2016 (in thousands) 2017 2016 Beginning asset retirement obligations $ 6,013 $ 5,075 Liabilities acquired (1) 359 250 Liabilities incurred 77 165 Property dispositions (1) (4,401 ) — Liabilities settled (9 ) (15 ) Accretion expense 434 551 Revision of estimates (119 ) (13 ) Ending asset retirement obligations $ 2,354 $ 6,013 (1) See Note 3. Acquisitions and Divestitures

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 14. Related Party Transactions FASB ASC Topic 850 , Related Party Disclosures Flatonia Energy, LLC (“Flatonia”), which owns approximately 10.7% of the outstanding Class A Common Stock as of December 31, 2017, 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 of south Texas. In connection with the Operating Agreement, the Company made payments to Flatonia of $26.5 million, $26.6 million and $33.9 million, and received payments from Flatonia of $5.4 million, $21.7 million and $66.7 million, respectively, for the years ended December 31, 2017, 2016 and 2015. At December 31, 2017 and 2016, amounts receivable due from Flatonia in connection with the Operating Agreement were $1.3 million and $1.5 million, respectively. Amounts payable due to Flatonia in connection with the Operating Agreement were $3.1 million at December 31, 2016. There were no payables outstanding and due to Flatonia as of December 31, 2017. Our majority shareholder consists of various investment funds managed by a venture capital firm who may manage other investments in entities with which we interact in the normal course of business.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15. Commitments and Contingencies Contractual Commitments Future minimum contractual commitments as of December 31, 2017 under non-cancelable agreements having remaining terms in excess of one year are as follows: 2018 2019 2020 2021 2022 Thereafter Gas contract $ 1,643 $ 1,643 $ 1,647 $ 680 $ — $ — Office leases 854 723 — — — — Total $ 2,497 $ 2,366 $ 1,647 $ 680 $ — $ — The Company has a non-cancelable fixed cost agreement of $1.6 million per year through 2021 to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing related to certain Eagle Ford assets in south Texas through 2021. Additionally, the Company leases corporate office space in The Woodlands, Texas, Midland, Texas and Denver, Colorado. Rent expense was approximately $0.9 million, $0.8 million, and $0.8 million for the years ended December 31, 2017, 2016, and 2015, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2017 are shown in the table above. Environmental The Company’s operations are subject to risks normally associated with the drilling, completion and production of oil and gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Company to liabilities associated with these risks. In the Company’s acquisition of existing or previously drilled well bores, the Company 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. The Company maintains comprehensive insurance coverage that it believes 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 fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above. Legal From time to time, Earthstone and its subsidiaries may be involved in various legal proceedings and claims in the ordinary course of business. In July 2015, EF Non-Op, LLC, a subsidiary of Earthstone, filed suit in the 125 th EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP), 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, Bold, Bold Holdings and OVR. The complaint alleges that Earthstone’s directors breached their fiduciary duties in connection with the Bold Contribution Agreement. 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. Earthstone and each of the other defendants believe the claims are entirely without merit and they intend to mount a vigorous defense. The 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. On August 18, 2017, litigation captioned Trinity Royal Partners, LP v. Bold Energy III LLC, et al.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 16. Income Taxes The following table shows the components of the Company’s income tax provision for the years ended December 31, 2017, 2016 and 2015 ( in thousands Years Ended December 31, 2017 2016 2015 Current: Federal $ — $ — $ — State (15 ) — (91 ) Total current (15 ) — (91 ) Deferred: Federal 16,186 (515 ) 26,214 State 202 (13 ) 319 Total deferred 16,388 (528 ) 26,533 Total income tax benefit (provision) $ 16,373 $ (528 ) $ 26,442 Effective Tax Rate Following the closing of the Bold Transaction, the Company continues to record an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from the Lynden Arrangement that includes 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. Following the Bold Transaction, Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. 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. A reconciliation of the effective tax rate to the statutory rate for the years ended December 31, 2017 and 2016 is as follows ( in thousands, except percentages Years Ended December 31, 2017 2016 U.S. Canada Total U.S. Canada Total Net loss before income taxes $ (61,082 ) $ (24 ) $ (61,106 ) $ (54,032 ) $ 19 $ (54,013 ) Statutory rate 34 % 26 % 34 % 26 % Tax benefit computed at statutory rate (20,768 ) (8 ) (20,776 ) (18,370 ) 5 (18,365 ) Noncontrolling interest 12,118 — 12,118 — — — Non-deductible impairment of goodwill — — — 5,961 — 5,961 Non-deductible transaction costs — — — 878 — 878 Non-deductible general and administrative expenses 168 — 168 5 — 5 Return to accrual (486 ) — (486 ) 15 — 15 State income taxes, net of Federal benefit (191 ) — (191 ) (128 ) — (128 ) Valuation allowance (15,483 ) 6 (15,477 ) 12,167 (5 ) 12,162 Federal rate change 7,824 — 7,824 — — — State rate change 445 — 445 — — — Rate differential on Canadian activity — 2 2 — — — Total income tax (benefit) expense $ (16,373 ) $ — $ (16,373 ) $ 528 $ — $ 528 Effective tax rate 26.8 % 0.0 % 26.8 % -1.0 % 0.0 % -1.0 % During the year ended December 31, 2017, the Company recorded a total income tax benefit of $16.4 million which was primarily driven by the change in valuation allowance associated with the Bold Transaction. For Lynden US, the Company recorded an income tax benefit of $8.6 million, of which $4.8 million related to the reduction of that amount in its deferred tax liability resulting from the federal corporate income tax rate reduction to 21% as described below. Additionally, the Company recorded an income tax benefit for Earthstone of $7.7 million which resulted from a change in assessment of the realization of its net deferred tax assets due to the deferred tax liability that was recorded with respect to its investment in EEH as part of the Bold Transaction as an adjustment to Additional paid-in capital within the Consolidated Balance Sheet. Additionally, Earthstone recorded income tax expense of $12.6 million related to the reduction of that amount in its deferred tax asset resulting from the federal corporate income tax rate reduction to 21% as described below, which was fully offset by the reduction in its valuation allowance for that amount because the future realization of such loss cannot be reasonably assured and is subject to a full valuation allowance. On December 22, 2017, the United States enacted tax reform legislation commonly known as the TCJA, resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes the federal corporate income tax rate reduction The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change. The Company’s effective tax rate for the year ended December 31, 2016, was approximately (1.0)% which was less than the U.S. Federal statutory tax rate primarily due to both the recording of a $12.2 million valuation allowance as the realizability of the Company’s deferred tax assets is not more likely-than-not, and $6.0 million reduction of income tax benefit resulting from non-deductible impairment of goodwill. A reconciliation of the effective tax rate to the statutory rate for the year ended December 31, 2015 is as follows ( in thousands, except percentages Year Ended December 31, 2015 Net loss before income taxes $ (143,097 ) Tax benefit computed at Federal statutory rate (48,653 ) Non-deductible general and administrative expenses 534 Return to accrual (1,398 ) State income taxes, net of Federal benefit (743 ) Valuation allowance 23,818 Total income tax (benefit) expense $ (26,442 ) Effective tax rate 18.5 % The Company’s effective tax rate for the year ended December 31, 2015, was approximately 18.5% which was less than the U.S. Federal statutory tax rate primarily due to the increase in valuation allowance in 2015. The impairments recorded by the Company during 2015 reduced the book value of its properties below the tax basis; thereby, giving rise to a significant deferred tax asset associated with its oil and natural gas properties and putting the Company in an overall net deferred tax asset position prior to any realization assessment. The realizability of the Company’s deferred tax assets is not more likely-than-not, therefore the Company recorded a valuation allowance to reduce its overall net deferred tax asset portion to zero. Deferred Tax Assets and Liabilities The Company's deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows ( in thousands December 31, 2017 2016 Deferred noncurrent income tax assets (liabilities): Office and other equipment $ — $ (48 ) Oil & gas properties 2,998 7,428 Asset retirement obligation — 2,042 Basis difference in subsidiary obligation (2,268 ) (4,226 ) Intangible assets — 36 Unrealized derivative loss — 2,145 Stock-based compensation — 1,148 Investment in Partnerships (111 ) — Federal net operating loss carryforward 12,986 15,109 Other — 186 Net deferred noncurrent tax assets 13,605 23,820 Valuation allowance (24,120 ) (39,596 ) Net deferred tax liability $ (10,515 ) $ (15,776 ) As of December 31, 2017, the Company had a valuation allowance recorded against its deferred tax assets of $24.1 million which is in excess of its net deferred noncurrent tax assets of $13.6 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal corporate income tax returns, one separate U.S. Federal partnership income tax return and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2017, the deferred tax assets and liabilities related to the two U.S. Federal corporate income tax returns and one Canadian income tax return are a $20.5 million deferred tax asset, an $8.5 million deferred tax liability and a $3.6 million deferred tax asset, respectively, before considering the valuation allowance of $24.1 million. As of December 31, 2016, the Company had a valuation allowance recorded against its deferred tax assets of $39.6 million which is in excess of its Net deferred noncurrent tax assets of $23.8 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2016, the deferred tax assets and liabilities related to the two U.S. Federal income tax returns and one Canadian income tax return are a $36.0 million deferred tax asset, a $15.8 million deferred tax liability and a $3.6 million deferred tax asset, respectively. As of December 31, 2017, the Company had estimated U.S. net operating loss carryforwards of $49.1 million, the first expiring in 2034 and the last in 2037, and estimated Canadian net operating loss carryforwards of $10.0 million, the first expiring in 2024 and the last in 2036. The ability to utilize net operating losses and other tax attributes could be subject to a significant limitation if the Company were to undergo an ownership change for the purposes of Section 382 (“Sec 382”) of the Internal Revenue Code of 1986, as amended (the “Code”). The Company has an additional estimated U.S. net operating loss carryforward of $28.0 million limited by Sec 382 resulting from the Lynden Arrangement. The Company continues to evaluate the impact, if any, of potential Sec 382 limitations. Uncertain Tax Positions FASB ASC Topic 740, Income Taxes The Company files two federal income tax returns, one Canadian income tax return and various combined and separate filings in several state and local jurisdictions. The Company’s practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statement of Operations. As of December 31, 2017, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.

Profit Sharing Plan

Profit Sharing Plan	12 Months Ended
	Dec. 31, 2017
Compensation And Retirement Disclosure [Abstract]
Profit Sharing Plan	Note 17. Profit Sharing Plan The Company sponsors a 401(k) defined contribution plan (the “401(k) Plan”) for substantially all of its employees, which was initiated in April 2017. Eligible employees may make contributions to the 401(k) Plan by electing to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to six percent of the eligible employee’s annual compensation contributed. The Company’s matching contributions vest immediately. The Company’s contributions to the 401(k) Plan for the year ended December 31, 2017 were $0.3 million.

Supplemental Selected Quarterly

Supplemental Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Supplemental Selected Quarterly Financial Data (Unaudited)	Note 18. Supplemental Selected Quarterly Financial Data (Unaudited) First Second Third Fourth (In thousands, except per share data) Quarter Quarter Quarter Quarter 2017 Oil and gas revenues $ 15,343 $ 25,777 $ 31,282 $ 35,676 (Loss) income from operations (3,433 ) (67,093 ) 8,546 12,105 Net income (loss) attributable to Earthstone Energy, Inc. 729 (17,123 ) 1,556 2,324 Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ 0.03 $ (0.75 ) $ 0.07 $ 0.09 2016 Oil and gas revenues $ 6,810 $ 9,777 $ 10,530 $ 15,152 Loss from operations (6,836 ) (6,433 ) (4,316 ) (28,436 ) Net loss attributable to Earthstone Energy, Inc. (6,421 ) (11,172 ) (3,900 ) (33,048 ) Net loss per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ (0.46 ) $ (0.69 ) $ (0.17 ) $ (1.48 ) Second quarter 2017 loss from operations includes a non-cash impairment charge of $66.6 million related to the Company’s oil and natural gas properties, as discussed in Note 6. Oil and Natural Gas Properties. Fourth quarter 2016 loss from operations includes a non-cash impairment charge of $6.8 million related to the Company’s oil and natural gas properties, as discussed in Note 6. Oil and Natural Gas Properties Note 7. Goodwill Note 12. Long-Term Debt

Supplemental Information On Oil

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Oil and Gas Exploration and Production Industries Activities	SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) Costs Incurred Related to Oil and Gas Activities Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. The Company’s oil and natural gas activities for 2017, 2016 and 2015 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows ( in thousands Years Ended December 31, 2017 (1) 2016 2015 Acquisition cost: Proved $ 315,376 $ 48,116 $ 4,508 Unproved 245,589 26,600 10,646 Exploration costs: Exploratory drilling — — — Geological and geophysical 1 5 142 Development costs 77,876 28,577 56,862 Total additions $ 638,842 $ 103,298 $ 72,158 (1) Acquisition costs incurred during 2017 consisted primarily of the assets acquired in the Bold Transaction described in Note 3. Acquisitions and Divestitures During the year ended December 31, 2017, additions to oil and natural gas properties of $0.1 million were recorded for estimated costs of future abandonment related to new wells drilled or acquired. During the years ended December 31, 2016 and 2015, additions to oil and natural gas properties of $0.2 million were recorded for estimated costs of future abandonment related to new wells drilled or acquired. For the years ended December 31, 2017, 2016 and 2015, the Company had no capitalized exploratory well costs, nor costs related to share-based compensation, general corporate overhead or similar activities. Capitalized Costs Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2017 and 2016, are summarized below ( in thousands December 31, 2017 2016 Oil and gas properties, successful efforts method: Proved properties $ 714,180 $ 476,832 Accumulated impairment to proved properties (103,608 ) (113,760 ) Proved properties, net of accumulated impairments 610,572 363,072 Unproved properties 319,569 100,612 Accumulated impairment to Unproved properties (44,543 ) (48,889 ) Unproved properties, net of accumulated impairments 275,026 51,723 Total oil and gas properties, net of accumulated impairments 885,598 414,795 Accumulated depreciation, depletion and amortization (118,028 ) (145,393 ) Net oil and gas properties $ 767,570 $ 269,402 Oil and Natural Gas Reserves Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. The proved reserves estimates shown herein for the years ended December 31, 2017, 2016 and 2015 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. The reserve information in these Consolidated Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced. The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2017, 2016, and 2015 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices which equates to $51.34 per barrel, $42.75 per barrel, and $50.28 per barrel, respectively. The natural gas prices as of December 31, 2017, 2016 and 2015 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.98 per MMBtu, $2.48 per MMBtu and $2.59 per MMBtu, respectively. Natural gas liquids are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics. The natural gas liquids prices used to value reserves as of December 31, 2017, 2016 and 2015 averaged $22.59 per barrel, $13.21 per barrel and $14.11 per barrel, respectively. A summary of the Company’s changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2017, 2016 and 2015 are as follows: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBOE) Balance - December 31, 2014 13,803 38,579 1,959 22,192 Extensions and discoveries 526 828 21 685 Sales of minerals in place (4 ) (8,040 ) — (1,344 ) Purchases of minerals in place 1,641 679 208 1,962 Production (904 ) (2,143 ) (176 ) (1,437 ) Revision to previous estimates (5,701 ) (16,565 ) (1,022 ) (9,484 ) Balance - December 31, 2015 9,361 13,338 990 12,574 Extensions and discoveries 345 285 30 423 Purchases of minerals in place 5,548 14,770 2,637 10,647 Production (878 ) (2,171 ) (225 ) (1,465 ) Revision to previous estimates (7,265 ) (5,821 ) (1,892 ) (10,128 ) Balance - December 31, 2016 7,111 20,401 1,540 12,051 Extensions and discoveries 19,558 29,644 6,264 30,763 Sales of minerals in place (1,833 ) (6,853 ) (1 ) (2,976 ) Purchases of minerals in place 28,176 46,709 9,950 45,911 Production (1,828 ) (3,260 ) (500 ) (2,872 ) Revision to previous estimates (3,857 ) 4,447 215 (2,901 ) Balance - December 31, 2017 (1) 47,327 91,088 17,468 79,976 Proved developed reserves: December 31, 2014 6,093 16,214 1,005 9,800 December 31, 2015 6,114 10,954 673 8,613 December 31, 2016 6,052 13,545 1,051 9,361 December 31, 2017 (2) 11,949 23,336 4,123 19,961 Proved undeveloped reserves: December 31, 2014 7,710 22,365 954 12,392 December 31, 2015 3,247 2,384 317 3,961 December 31, 2016 1,059 6,856 489 2,690 December 31, 2017 (3) 35,378 67,752 13,345 60,015 (1) Includes 26.8 MMBbl of oil, 51.6 Bcf of natural gas and 9.9 MMBbl of NGL reserves attributable to noncontrolling interests. (2) Includes 6.8 MMBbl of oil, 13.2 Bcf of natural gas and 2.3 MMBbl of NGL reserves attributable to noncontrolling interests. (3) Includes 20.0 MMBbl of oil, 38.4 Bcf of natural gas and 7.6 MMBbl of NGL reserves attributable to noncontrolling interests. Notable changes in proved reserves for the year ended December 31, 2017 included the following: • Extensions and discoveries. In 2017, total extensions and discoveries of 30,763 MBOE was a result of successful drilling results and well performance primarily related to the Midland Basin. The closing of the Bold Transaction in May 2017 which included primarily operated acreage in the Midland Basin was a significant contributor to this. • Sales of minerals in place. Sales of minerals in place totaled 2,976 MBOE during 2017 and were primarily related to the disposition of the Bakken properties, as further described in in the Notes to Consolidated Financial Statements. • Purchases of minerals in place. In 2017, total purchases of minerals in place of 45,911 MBOE were primarily attributable to the Bold Transaction, whereby the Company acquired interests in 63 producing oil and natural gas wells, four proved developed non-producing wells and undeveloped acreage in the Midland Basin, as further described in in the Notes to Consolidated Financial Statements • Revision to previous estimates. In 2017, the downward revisions of prior reserves of 2,901 MBOE consisted of negative revisions to PUD reserves of 4,832 MBOE with improved proved developed reserves of 1,931 MBOE. PUD revisions are a result of (1) removal of approximately 2,011 MBOE of reserves due to delayed development plans of other operators in the Midland Basin that management previously expected to be developed within five years, (2) reduction of 2,378 MBOE upon closing of the Bold Transaction and making adjustments to development plans and PUD reserve assignments, and (3) non-participation in three Eagle Ford natural gas PUDs that were expected to develop 443 MBOE. Positive revisions are primarily a result of increased oil and natural gas prices during 2017. Notable changes in proved reserves for the year ended December 31, 2016 included the following: • Extension and discoveries. In 2016, total extensions and discoveries of 423 MBOE were primarily attributable to the successful drilling on the operated Eagle Ford and non-operated Bakken properties. • Purchase of minerals in place. In 2016, total purchases of minerals in place of 10,647 MBOE were primarily attributable to the Lynden Arrangement, whereby the Company acquired interests in non-operated Midland Basin properties. • Revision to previous estimates. In 2016, the downward revision to previous estimates of 10,128 MBOE for total proved reserves occurred primarily as a result of decreased oil and natural gas prices. Notable changes in proved reserves for the year ended December 31, 2015 included the following: • Extensions and discoveries. In 2015, total extensions and discoveries of 685 MBOE were primarily attributable to the successful drilling on the operated Eagle Ford and non-operated Bakken properties. • Sales of minerals in place. Sales of minerals in place totaled 1,344 MBOE during 2015 and were primarily related to the disposition of the Company’s Louisiana properties, as further described in in the Notes to Consolidated Financial Statements. • Purchases of minerals in place. In 2015, total purchases of minerals in place of 1,962 MBOE were primarily attributable to interests acquired in the Eagle Ford Trend. • Revision to previous estimates. In 2015, the downward revision to previous estimates of 9,484 MBOE for total proved reserves occurred primarily as a result of decreased oil and natural gas prices. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and analogous producing wells for each area or field. PUD locations were limited to areas of uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the basis of available geoscience and engineering data. Changes in PUD reserves for the years ended December 31, 2017, 2016 and 2015 were as follows ( in MBOE Proved undeveloped reserves at December 31, 2014 12,392 Conversions to developed (1,700 ) Extensions and discoveries 685 Purchases of minerals in place 1,924 Revision to previous estimates (9,340 ) Proved undeveloped reserves at December 31, 2015 3,961 Conversions to developed (169 ) Extensions and discoveries 293 Purchases of minerals in place 873 Revision to previous estimates (2,268 ) Proved undeveloped reserves at December 31, 2016 2,690 Conversions to developed (2,756 ) Extensions and discoveries 27,977 Sales of minerals in place (391 ) Purchases of minerals in place 37,327 Revision to previous estimates (4,832 ) Proved undeveloped reserves at December 31, 2017 (1) 60,015 (1) Includes 34,029 MBOE attributable to noncontrolling interests. 2017 Changes in PUD reserves Conversions to developed . In the Company’s year-end 2016 plan to develop its PUDs within five years, the Company estimated that $6.9 million of capital would be expended in 2017 and that it would convert 732 MBOE. Because of the improvement in commodity prices and the change in its development plan for 2017, the Company actually spent $8.5 million to convert 622 MBOE to developed. The Company’s plan changed in that it developed more oil PUDs and elected not to participate in natural gas PUDs which included the above mentioned 443 MBOE associated with the Eagle Ford non-participation. The capital to develop the Company’s oil PUDs was higher on a per unit basis than the natural gas PUDs however the margins are higher for oil PUDs. The oil PUDs further benefited the Company’s longer-term operated development plans. Since the Bold Transaction closed in May 2017, the associated capital plan for the properties acquired in the Bold Transaction during 2017 was not considered in the Company’s year-end 2016 report. The Company did however incur $63.4 million to convert 2,134 MBOE of purchased PUD reserves to Developed. The Company intends to convert its proved undeveloped reserves into proved developed producing reserves in accordance with its estimates as of the date of the Company’s year-end 2017 reserve report . Extensions and discoveries . Additionally, 27,977 MBOE were added as extensions and discoveries due to successful drilling results on the Company’s acreage positions because of the wells it drilled. The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to the Company’s acreage. All of these drilling results increased the confidence of the reservoir continuity and performance of the associated reservoirs which increased the number of PUDs primarily in the Midland Basin. Sales of minerals in place. Sales of minerals in place totaled 391 MBOE during 2017 and were primarily related to the disposition of the Bakken properties, as further described in in the Notes to Consolidated Financial Statements Purchases of minerals in place . During 2017, 37,327 MBOE were added to PUD reserves upon the closing of the Bold Transaction. Revision to previous estimates. Revisions of 4,832 MBOE were primarily due to (1) removal of approximately 2,011 MBOE of reserves due to delayed development plans of other operators in the Midland Basin that management previously expected to be developed within five years, (2) reduction of 2,378 MBOE upon the closing of the Bold Transaction and making adjustments to development plans and PUD reserve assignments, and (3) non-participation in three Eagle Ford natural gas PUDs that were expected to develop 443 MBOE. This non-participation has no impact on the Company’s ability to participate in future wells in this acreage position. 2016 Changes in PUD reserves In early 2016, due primarily to depressed prices of oil and natural gas, the Company placed a lower emphasis on the conversion of its PUDs into proved developed producing reserves. In the Company’s plan to convert these reserves over a five-year period, the Company estimated that $3.1 million of capital expenditure would be incurred in 2016, and the bulk of capital expenditures would occur over the following four years. The Company’s actual 2016 capital expenditures for conversion of proved undeveloped reserves were $3.2 million, in line with its estimates. The Company also had estimated that these capital expenditures would result in 258 MBOE of proved developed producing reserves. The Company’s actual estimated conversions were 169 MBOE. The difference was due primarily to one less location being drilled than the Company had estimated and lower initial reserve estimates for wells in certain units where all wells in the units had not been developed. This resulted in lower reserve estimates until the remaining wells in the units are drilled. As of December 31, 2016, the Company’s estimated proved undeveloped reserves were significantly lower than as of December 31, 2015, due to lower oil and natural gas prices used in making its 2016 estimates. Extensions and Discoveries during the year ended December 31, 2016, were from the Company’s operated Eagle Ford and non-operated Bakken properties. 2015 Changes in PUD reserves All of the Company’s purchases of minerals in place reserves during the year ended December 31, 2015, occurred in its Eagle Ford property in Gonzales County, Texas. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC Topic 932, Extractives Activities – Oil and Gas The Company believes that the following factors should be taken into account when reviewing the following information: • Future costs and commodity prices will probably differ from those required to be used in these calculations; • Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; • A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and • Future net revenues may be subject to different rates of income taxation. At December 31, 2017, 2016 and 2015, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Prices used to estimate reserves are included in Oil and Natural Gas Reserves The Standardized Measure is as follows ( in thousand December 31, 2017 2016 2015 Future cash inflows $ 2,948,989 $ 346,948 $ 481,131 Future production costs (757,716 ) (172,062 ) (192,349 ) Future development costs (677,093 ) (29,814 ) (91,725 ) Future income tax expense (33,644 ) — — Future net cash flows 1,480,536 145,072 197,057 10% annual discount for estimated timing of cash flows (887,836 ) (59,189 ) (92,661 ) Standardized measure of discounted future net cash flows (1) $ 592,700 $ 85,883 $ 104,396 (1) At December 31, 2017, the standardized measure of discounted future net cash flows includes $336.1 million attributable to noncontrolling interests. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2017 ( in thousands December 31, 2017 2016 2015 Beginning of year $ 85,883 $ 104,396 $ 255,856 Sales of oil and gas produced, net of production costs (81,926 ) (24,998 ) (29,152 ) Sales of minerals in place (15,553 ) — (2,470 ) Net changes in prices and production costs 155,629 (102,143 ) (288,064 ) Extensions, discoveries, and improved recoveries 201,801 241 6,514 Changes in income taxes, net (5,941 ) — 88,944 Previously estimated development costs incurred during the 76,447 27,770 26,977 Net changes in future development costs (168,940 ) 102,267 6,697 Purchases of minerals in place 244,785 16,921 7,695 Revisions of previous quantity estimates 68,705 (45,239 ) (16,671 ) Accretion of discount 28,985 11,506 25,586 Changes in timing of estimated cash flows and other 2,825 (4,838 ) 22,484 End of year (1) $ 592,700 $ 85,883 $ 104,396 (1) At December 31, 2017, the standardized measure of discounted future net cash flows includes $336.1 million attributable to noncontrolling interests.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation.
Use of Estimates	Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods then ended. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of our estimates. All reserve data included in these Consolidated Financial Statements are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered. Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, goodwill, asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)
Accounts Receivable	Accounts Receivable Accounts receivable include amounts due from crude oil, natural gas, and natural gas liquids purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and natural gas liquids sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability. Allowance for uncollectible accounts receivable was $0.1 million at and $0.2 million at December 31, 2017 and 2016, respectively.
Derivative Instruments	Derivative Instruments The Company utilizes derivative instruments in order to manage exposure to commodity price risk associated with future oil and natural gas production. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are mark-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties as prescribed by the SEC. For more information see Note 6. Oil and Natural Gas Properties .
Goodwill	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 carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. There were no impairments to Goodwill recorded in the year ended December 31, 2017. During the years ended December 31, 2016 and 2015, impairments to Goodwill of $17.5 million and $1.5 million, respectively, were recorded. For further discussion, see Note 7. Goodwill
Noncontrolling Interest	Noncontrolling Interest Noncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2017, as well as an adjustment to Net loss in the Consolidated Statement of Operations for the year ended December 31, 2017. As of December 31, 2017, Earthstone and Lynden US owned a 43.3% membership interest in EEH while Bold Holdings, the noncontrolling third party, owned the remaining 56.7%. See further discussion in Note 8. Noncontrolling Interest
Segment Reporting	Segment Reporting Operating segments are defined under FASB ASC Topic 280, Segment Reporting, as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas exploration and production. We consider drilling rig services ancillary to our oil and natural gas exploration and producing activities and manage these services to support such activities.
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For further discussion, see Note 13. Asset Retirement Obligations
Business Combinations	Business Combinations The Company accounts for the acquisition of oil and gas properties not commonly controlled based on the requirements of FASB ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved developed oil and gas properties as business combinations.
Revenue Recognition	Revenue Recognition Oil, natural gas, and natural gas liquids revenues represent income from the production and delivery of oil, natural gas, and natural gas liquids, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has been transferred, and collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. The Company had no significant gas imbalances as of December 31, 2017, 2016, or 2015.
Concentration of Credit Risk	Concentration of Credit Risk Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms. The purchasers of the Company’s oil, natural gas, and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2017, three purchasers accounted for 18%, 14% and 14%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In 2016, two purchasers accounted for 41% and 19%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In 2015, one purchaser accounted for 62% of the Company’s oil, natural gas, and natural gas liquids revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2017, 2016, and 2015. Additionally, at December 31, 2017, three purchasers accounted for 20%, 13% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. At December 31, 2016, two purchasers accounted for 28% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2017 and 2016. The Company holds working interests in oil and natural gas properties for which a third party serves as operator. The operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In 2017, 2016 and 2015, one operator distributed 10%, 19% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids revenues. No other operator accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2017, 2016, and 2015. The derivative instruments of the Company are with a small number of counterparties and, from time-to-time, may represent material assets in the Consolidated Balance Sheets. At December 31, 2017 and 2016, the Company had no derivative contracts that were in a material asset position. The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage.
Income Taxes	Income Taxes The Company is a U.S. company operating primarily in Texas, as of December 31, 2017, as well as one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which its operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, the Company is required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as its operations are conducted in different taxing jurisdictions. Following the closing of the Bold Transaction, the Company continues to record an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from Earthstone’s acquisition of Lynden Corp in May 2016 (the “Lynden Arrangement”) that includes 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. Following the Bold Transaction, Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. 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. The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in the Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2017 and 2016, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets. The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management and they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2017, 2016 or 2015. On December 22, 2017, the United States enacted tax reform legislation commonly known as the Tax Cuts and Jobs Act (the “TCJA”), resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes the federal corporate income tax rate reduction The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change .
Recently Issued Accounting Standards	Recently Issued Accounting Standards Accounting for the Tax Cuts and Jobs Act – In December 2017, the SEC Staff issued Staff Accounting Bulletin No. 118, (“SAB 118”), to supplement the accounting requirements of FASB ASC Topic 740, (ASC Topic 740), as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. In the fourth quarter of 2017, the Company remeasured its deferred taxes at 21%, in accordance with the TCJA and GAAP. For further details, see Note 16. Income Taxes Revenue Recognition - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers, which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. This new revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The new standard is now effective prospectively for reporting periods beginning on or after December 15, 2017. The Company has completed its evaluation of the new standard and will adopt the new standard, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements. The Company has elected to use the modified retrospective method for adoption and has updated its related internal control documentation, processes and controls to conform to the new standard. Leases – In February 2016, the FASB issued updated guidance on accounting for leases. The update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. Similar to current guidance, the update continues to differentiate between finance leases and operating leases; however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The standards update is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2019. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Consolidated Financial Statements. Statement of Cash Flows – In August 2016, the FASB issued updated guidance that clarifies how certain cash receipts and cash payments are presented in the statement of cash flows. This update provides guidance on eight specific cash flow issues. The standards update is effective for interim and annual periods beginning after December 15, 2017, and should be applied retrospectively to all periods presented. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Statements of Cash Flows. Business Combinations – In January 2017, the FASB issued updated guidance that clarifies the definition of a business, which amends the guidance used in evaluating whether a set of acquired assets and activities represents a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not considered a business. As a result, acquisition fees and expenses will be capitalized to the cost basis of the property acquired, and the tangible and intangible components acquired will be recorded based on their relative fair values as of the acquisition date. The standard is effective for all public business entities for annual periods beginning after December 15, 2017. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements. 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 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, if any, on its Consolidated Financial Statements. Compensation – Stock Compensation – In May 2017, the FASB issued updated guidance that provides clarity about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables) - Bold Contribution Agreement [Member]	12 Months Ended
	Dec. 31, 2017
Business Acquisition [Line Items]
Schedule of Consideration Transferred, Fair Value of Assets Acquired and Liabilities Assumed	The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed ( in thousands, except share and share price amounts Consideration: Shares of Class A Common Stock issued pursuant to the Bold Contribution Agreement to certain employees of Bold 150,000 EEH Units issued to Bold Holdings 36,070,828 Total equity interest issued in the Bold Transaction 36,220,828 Closing per share price of Class A Common Stock as of May 9, 2017 $ 13.58 Total consideration transferred (1) (2) $ 491,879 Fair value of assets acquired: Cash and cash equivalents $ 2,355 Other current assets 10,078 Oil and gas properties (3) 557,704 Amount attributable to assets acquired $ 570,137 Fair value of liabilities assumed: Long-term debt (4) $ 58,000 Current liabilities 17,042 Deferred tax liability 2,857 Noncurrent asset retirement obligations 359 Amount attributable to liabilities assumed $ 78,258 (1) Consideration included 150,000 shares of Class A Common Stock recorded above based upon its fair value which was determined using the closing price of $13.58 per share on May 9, 2017. (2) Consideration was 36,070,828 EEH Units. Additionally, Bold Holdings purchased 36,070,828 shares of Class B Common Stock for $36,071. Each EEH Unit, together with one share of Class B Common Stock, is convertible into one share of Class A Common Stock. The fair value of the consideration was determined using the closing price of the Company’s Class A Common Stock of $13.58 per share on May 9, 2017. (3) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projections of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 3. Fair Value Measurements (4) Concurrent with the closing of the Bold Transaction, EEH repaid Bold’s outstanding borrowings of $58.0 million under its credit agreement.
Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed	The following unaudited supplemental pro forma condensed results of operations present consolidated information as though the Bold Transaction and the Bakken Sale (discussed below) had been completed as of January 1, 2016. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for Bold and Earthstone and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired and (ii) to eliminate non-recurring transaction costs directly related to the Bold Transaction that do not have a continuing impact on the Company’s operating results. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information ( in thousands, except per share amounts Years ended December 31, 2017 2016 (Unaudited) Revenue $ 126,839 $ 54,436 Loss before taxes $ (44,461 ) $ (40,564 ) Net loss $ (35,617 ) $ (41,092 ) Less: Net loss attributable to noncontrolling interest $ (22,005 ) $ (27,012 ) Net loss attributable to Earthstone Energy, Inc. $ (13,612 ) $ (14,080 ) Pro forma net loss per common share attributable to Earthstone Energy, Inc.: Basic and Diluted $ (0.57 ) $ (0.75 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Summary of Fair Value of Financial Assets and Liabilities	The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands) December 31, 2017 Level 1 Level 2 Level 3 Total Financial assets Derivative asset- current $ — $ 184 $ — $ 184 Total financial assets $ — $ 184 $ — $ 184 Financial liabilities Derivative liability - current $ — $ 11,805 $ — $ 11,805 Derivative liability - noncurrent — 1,826 — 1,826 Total financial liabilities $ — $ 13,631 $ — $ 13,631 December 31, 2016 Financial liabilities Derivative liability - current $ — $ 4,595 $ — $ 4,595 Derivative liability - noncurrent — 1,575 — 1,575 Total financial liabilities $ — $ 6,170 $ — $ 6,170

Derivative Financial Instrume31

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Derivative Contracts	The following table sets forth the Company’s outstanding derivative contracts at December 31, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed. Period Commodity Volume (Bbl s Price ($/Bbl / $/MMBtu) 2018 Crude Oil Swap 1,483,250 $ 51.38 2018 Crude Oil Basis Swap (1) 602,250 $ (0.15 ) 2019 Crude Oil Swap 547,500 $ 52.32 2018 Natural Gas Swap 810,000 $ 3.066 (1) The basis differential price is between Midland – West Texas Intermediate (“WTI”) and the NYMEX – WTI
Schedule of Location and Fair Value Amounts of All Derivative Instruments	The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets (in thousands) December 31, 2017 December 31, 2016 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 Derivative asset - current $ 184 $ — $ 184 $ — $ — $ — Commodity contracts Derivative liability - current $ 11,805 $ — $ 11,805 $ 4,595 $ — $ 4,595 Commodity contracts Derivative liability - noncurrent $ 1,826 $ — $ 1,826 $ 1,575 $ — $ 1,575
Summary of Realized and Unrealized Gains and Losses on Derivative Instruments	The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Company’s Consolidated Statements of Operations (in thousands) Years Ended December 31, 2017 2016 2015 Derivatives not designated as hedging contracts under ASC Topic 815 Statement of Operations Location Total (loss) gain on commodity contracts (Loss) gain on derivative contracts, net $ (7,278 ) $ (9,863 ) $ 125 Cash settlements on commodity contracts (Loss) gain on derivative contracts, net (708 ) 3,225 6,306 (Loss) gain on commodity contracts, net $ (7,986 ) $ (6,638 ) $ 6,431

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Impairment Charges [Abstract]
Schedule of Non-Cash Asset Impairment Charges	The Company had the following non-cash asset impairment charges to its oil and natural gas properties for the years ended December 31, 2017, 2016 and 2015 ( in thousands Years Ended December 31, 2017 2016 2015 Proved property $ 63,131 $ 2,873 $ 93,984 Unproved property 9,060 3,878 42,555 Total $ 72,191 $ 6,751 $ 136,539

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Summary of Non-Cash Impairment Charges to Goodwill	The Company had the following non-cash impairment charges to its goodwill for the years ended December 31, 2016 and 2015 ( in thousands Years Ended December 31, 2016 2015 Impairment expense - goodwill $ 17,532 $ 1,547

Noncontrolling Interest (Tables

Noncontrolling Interest (Tables)	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
Reconciliation of Equity Attributable to Noncontrolling Interest	A reconciliation of the equity attributable to the noncontrolling interest as of May 9, 2017 is as follows ( in thousands Total considerations transferred (1) $ 491,879 Change to additional paid-in capital to reflect the noncontrolling interest within equity at their membership interest (12,872 ) Portion of equity attributable to noncontrolling interest (2) $ 479,007 (1) See Note 3. Acquisitions and Divestitures (2) Represents 61.4% of total equity attributable to EEH as of May 9, 2017.
Summary of Changes in Noncontrolling Interest	The following table presents the changes in noncontrolling interest for the year ended December 31, 2017: EEH Units Held By Earthstone and Lynden US % EEH Units Held By Others % Total EEH Units Outstanding As of December 31, 2016 — — — — — May 9, 2017 - Bold Transaction 22,656,624 38.6 % 36,070,828 61.4 % 58,727,452 EEH Units issued in connection with Class A Common Stock issued in connection with the Bold Transaction 150,000 — 150,000 EEH Units issued in connection with the vesting of restricted stock units and issuance of Class A Common Stock 259,355 — 259,355 EEH Units issued in connection with Class A Common Stock offering 4,500,000 — 4,500,000 EEH Units and Class B Common Stock converted to Class A Common Stock 18,659 (18,659 ) - As of December 31, 2017 27,584,638 43.3 % 36,052,169 56.7 % 63,636,807
Summary of Activity for Equity Attributable to Noncontrolling Interest	The following table summarizes the activity for the equity attributable to the noncontrolling interest for the year ended December 31, 2017 ( in thousands 2017 As of December 31, 2016 $ — Noncontrolling interest recorded within equity in connection with the closing of the Bold Transaction 479,007 EEH Units and Class B Common Stock converted to Class A Common Stock (230 ) Net loss attributable to noncontrolling interest (32,219 ) As of December 31, 2017 $ 446,558

Net Loss Per Common Share (Tabl

Net Loss Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Reconciliation of Net Loss Per Common Share	A reconciliation of Net loss per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2017 2016 2015 Net loss attributable to Earthstone Energy, Inc. $ (12,514 ) $ (54,541 ) $ (116,655 ) Net loss per common share attributable to Earthstone Energy, Inc.: Basic $ (0.53 ) $ (2.92 ) $ (8.43 ) Diluted $ (0.53 ) $ (2.92 ) $ (8.43 ) Weighted average common shares outstanding Basic 23,589,973 18,651,582 13,835,128 Add potentially dilutive securities: Unvested restricted stock units — — — Diluted weighted average common shares outstanding 23,589,973 18,651,582 13,835,128

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Unvested RSU Award Activity	The table below summarizes unvested RSU activity for the year ended December 31, 2017: Shares Weighted-Average Grant Date Fair Value Unvested RSUs at December 31, 2016 781,500 $ 12.53 Granted 949,000 $ 9.80 Forfeited (58,041 ) $ 12.98 Vested (703,214 ) $ 12.44 Unvested RSUs at December 31, 2017 969,245 $ 9.89

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Summary of Long Term Debt	The following table below summarizes long term debt ( in thousands December 31, 2017 2016 Credit Agreement $ 25,000 $ 10,000 Promissory note — 4,297 Total debt 25,000 14,297 Less: Current portion of long-term debt — (1,604 ) Long-term debt $ 25,000 $ 12,693

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Summary of Asset Retirement Obligation Transactions	The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended December 31, 2017 and 2016 (in thousands) 2017 2016 Beginning asset retirement obligations $ 6,013 $ 5,075 Liabilities acquired (1) 359 250 Liabilities incurred 77 165 Property dispositions (1) (4,401 ) — Liabilities settled (9 ) (15 ) Accretion expense 434 551 Revision of estimates (119 ) (13 ) Ending asset retirement obligations $ 2,354 $ 6,013 (1) See Note 3. Acquisitions and Divestitures

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Contractual Commitments under Non-cancelable Agreements	Future minimum contractual commitments as of December 31, 2017 under non-cancelable agreements having remaining terms in excess of one year are as follows: 2018 2019 2020 2021 2022 Thereafter Gas contract $ 1,643 $ 1,643 $ 1,647 $ 680 $ — $ — Office leases 854 723 — — — — Total $ 2,497 $ 2,366 $ 1,647 $ 680 $ — $ —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Components of Income Tax Provision	The following table shows the components of the Company’s income tax provision for the years ended December 31, 2017, 2016 and 2015 ( in thousands Years Ended December 31, 2017 2016 2015 Current: Federal $ — $ — $ — State (15 ) — (91 ) Total current (15 ) — (91 ) Deferred: Federal 16,186 (515 ) 26,214 State 202 (13 ) 319 Total deferred 16,388 (528 ) 26,533 Total income tax benefit (provision) $ 16,373 $ (528 ) $ 26,442
Reconciliation of Effective Tax Rate to Statutory Rate	A reconciliation of the effective tax rate to the statutory rate for the years ended December 31, 2017 and 2016 is as follows ( in thousands, except percentages Years Ended December 31, 2017 2016 U.S. Canada Total U.S. Canada Total Net loss before income taxes $ (61,082 ) $ (24 ) $ (61,106 ) $ (54,032 ) $ 19 $ (54,013 ) Statutory rate 34 % 26 % 34 % 26 % Tax benefit computed at statutory rate (20,768 ) (8 ) (20,776 ) (18,370 ) 5 (18,365 ) Noncontrolling interest 12,118 — 12,118 — — — Non-deductible impairment of goodwill — — — 5,961 — 5,961 Non-deductible transaction costs — — — 878 — 878 Non-deductible general and administrative expenses 168 — 168 5 — 5 Return to accrual (486 ) — (486 ) 15 — 15 State income taxes, net of Federal benefit (191 ) — (191 ) (128 ) — (128 ) Valuation allowance (15,483 ) 6 (15,477 ) 12,167 (5 ) 12,162 Federal rate change 7,824 — 7,824 — — — State rate change 445 — 445 — — — Rate differential on Canadian activity — 2 2 — — — Total income tax (benefit) expense $ (16,373 ) $ — $ (16,373 ) $ 528 $ — $ 528 Effective tax rate 26.8 % 0.0 % 26.8 % -1.0 % 0.0 % -1.0 % A reconciliation of the effective tax rate to the statutory rate for the year ended December 31, 2015 is as follows ( in thousands, except percentages Year Ended December 31, 2015 Net loss before income taxes $ (143,097 ) Tax benefit computed at Federal statutory rate (48,653 ) Non-deductible general and administrative expenses 534 Return to accrual (1,398 ) State income taxes, net of Federal benefit (743 ) Valuation allowance 23,818 Total income tax (benefit) expense $ (26,442 ) Effective tax rate 18.5 %
Components of Deferred Tax Assets and Liabilities	Significant components of the deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows ( in thousands December 31, 2017 2016 Deferred noncurrent income tax assets (liabilities): Office and other equipment $ — $ (48 ) Oil & gas properties 2,998 7,428 Asset retirement obligation — 2,042 Basis difference in subsidiary obligation (2,268 ) (4,226 ) Intangible assets — 36 Unrealized derivative loss — 2,145 Stock-based compensation — 1,148 Investment in Partnerships (111 ) — Federal net operating loss carryforward 12,986 15,109 Other — 186 Net deferred noncurrent tax assets 13,605 23,820 Valuation allowance (24,120 ) (39,596 ) Net deferred tax liability $ (10,515 ) $ (15,776 )

Supplemental Selected Quarter41

Supplemental Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Selected Quarterly Financial Data	First Second Third Fourth (In thousands, except per share data) Quarter Quarter Quarter Quarter 2017 Oil and gas revenues $ 15,343 $ 25,777 $ 31,282 $ 35,676 (Loss) income from operations (3,433 ) (67,093 ) 8,546 12,105 Net income (loss) attributable to Earthstone Energy, Inc. 729 (17,123 ) 1,556 2,324 Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ 0.03 $ (0.75 ) $ 0.07 $ 0.09 2016 Oil and gas revenues $ 6,810 $ 9,777 $ 10,530 $ 15,152 Loss from operations (6,836 ) (6,433 ) (4,316 ) (28,436 ) Net loss attributable to Earthstone Energy, Inc. (6,421 ) (11,172 ) (3,900 ) (33,048 ) Net loss per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ (0.46 ) $ (0.69 ) $ (0.17 ) $ (1.48 )

Supplemental Information On O42

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Costs Incurred in Oil and Gas Producing Activities	The Company’s oil and natural gas activities for 2017, 2016 and 2015 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows ( in thousands Years Ended December 31, 2017 (1) 2016 2015 Acquisition cost: Proved $ 315,376 $ 48,116 $ 4,508 Unproved 245,589 26,600 10,646 Exploration costs: Exploratory drilling — — — Geological and geophysical 1 5 142 Development costs 77,876 28,577 56,862 Total additions $ 638,842 $ 103,298 $ 72,158 (1) Acquisition costs incurred during 2017 consisted primarily of the assets acquired in the Bold Transaction described in Note 3. Acquisitions and Divestitures
Summary of Capitalized Costs, Impairment, and Depreciation, Depletion and Amortization	Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2017 and 2016, are summarized below ( in thousands December 31, 2017 2016 Oil and gas properties, successful efforts method: Proved properties $ 714,180 $ 476,832 Accumulated impairment to proved properties (103,608 ) (113,760 ) Proved properties, net of accumulated impairments 610,572 363,072 Unproved properties 319,569 100,612 Accumulated impairment to Unproved properties (44,543 ) (48,889 ) Unproved properties, net of accumulated impairments 275,026 51,723 Total oil and gas properties, net of accumulated impairments 885,598 414,795 Accumulated depreciation, depletion and amortization (118,028 ) (145,393 ) Net oil and gas properties $ 767,570 $ 269,402
Summary of Changes in Quantities of Proved Oil and Natural Gas Reserves	A summary of the Company’s changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2017, 2016 and 2015 are as follows: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBOE) Balance - December 31, 2014 13,803 38,579 1,959 22,192 Extensions and discoveries 526 828 21 685 Sales of minerals in place (4 ) (8,040 ) — (1,344 ) Purchases of minerals in place 1,641 679 208 1,962 Production (904 ) (2,143 ) (176 ) (1,437 ) Revision to previous estimates (5,701 ) (16,565 ) (1,022 ) (9,484 ) Balance - December 31, 2015 9,361 13,338 990 12,574 Extensions and discoveries 345 285 30 423 Purchases of minerals in place 5,548 14,770 2,637 10,647 Production (878 ) (2,171 ) (225 ) (1,465 ) Revision to previous estimates (7,265 ) (5,821 ) (1,892 ) (10,128 ) Balance - December 31, 2016 7,111 20,401 1,540 12,051 Extensions and discoveries 19,558 29,644 6,264 30,763 Sales of minerals in place (1,833 ) (6,853 ) (1 ) (2,976 ) Purchases of minerals in place 28,176 46,709 9,950 45,911 Production (1,828 ) (3,260 ) (500 ) (2,872 ) Revision to previous estimates (3,857 ) 4,447 215 (2,901 ) Balance - December 31, 2017 (1) 47,327 91,088 17,468 79,976 Proved developed reserves: December 31, 2014 6,093 16,214 1,005 9,800 December 31, 2015 6,114 10,954 673 8,613 December 31, 2016 6,052 13,545 1,051 9,361 December 31, 2017 (2) 11,949 23,336 4,123 19,961 Proved undeveloped reserves: December 31, 2014 7,710 22,365 954 12,392 December 31, 2015 3,247 2,384 317 3,961 December 31, 2016 1,059 6,856 489 2,690 December 31, 2017 (3) 35,378 67,752 13,345 60,015 (1) Includes 26.8 MMBbl of oil, 51.6 Bcf of natural gas and 9.9 MMBbl of NGL reserves attributable to noncontrolling interests. (2) Includes 6.8 MMBbl of oil, 13.2 Bcf of natural gas and 2.3 MMBbl of NGL reserves attributable to noncontrolling interests. (3) Includes 20.0 MMBbl of oil, 38.4 Bcf of natural gas and 7.6 MMBbl of NGL reserves attributable to noncontrolling interests.
Changes in PUD Reserves	Changes in PUD reserves for the years ended December 31, 2017, 2016 and 2015 were as follows ( in MBOE Proved undeveloped reserves at December 31, 2014 12,392 Conversions to developed (1,700 ) Extensions and discoveries 685 Purchases of minerals in place 1,924 Revision to previous estimates (9,340 ) Proved undeveloped reserves at December 31, 2015 3,961 Conversions to developed (169 ) Extensions and discoveries 293 Purchases of minerals in place 873 Revision to previous estimates (2,268 ) Proved undeveloped reserves at December 31, 2016 2,690 Conversions to developed (2,756 ) Extensions and discoveries 27,977 Sales of minerals in place (391 ) Purchases of minerals in place 37,327 Revision to previous estimates (4,832 ) Proved undeveloped reserves at December 31, 2017 (1) 60,015 (1) Includes 34,029 MBOE attributable to noncontrolling interests.
Schedule Of Standardized Measure	The Standardized Measure is as follows ( in thousand December 31, 2017 2016 2015 Future cash inflows $ 2,948,989 $ 346,948 $ 481,131 Future production costs (757,716 ) (172,062 ) (192,349 ) Future development costs (677,093 ) (29,814 ) (91,725 ) Future income tax expense (33,644 ) — — Future net cash flows 1,480,536 145,072 197,057 10% annual discount for estimated timing of cash flows (887,836 ) (59,189 ) (92,661 ) Standardized measure of discounted future net cash flows (1) $ 592,700 $ 85,883 $ 104,396 (1) At December 31, 2017, the standardized measure of discounted future net cash flows includes $336.1 million attributable to noncontrolling interests.
Schedule Of Changes In Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves	The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2017 ( in thousands December 31, 2017 2016 2015 Beginning of year $ 85,883 $ 104,396 $ 255,856 Sales of oil and gas produced, net of production costs (81,926 ) (24,998 ) (29,152 ) Sales of minerals in place (15,553 ) — (2,470 ) Net changes in prices and production costs 155,629 (102,143 ) (288,064 ) Extensions, discoveries, and improved recoveries 201,801 241 6,514 Changes in income taxes, net (5,941 ) — 88,944 Previously estimated development costs incurred during the 76,447 27,770 26,977 Net changes in future development costs (168,940 ) 102,267 6,697 Purchases of minerals in place 244,785 16,921 7,695 Revisions of previous quantity estimates 68,705 (45,239 ) (16,671 ) Accretion of discount 28,985 11,506 25,586 Changes in timing of estimated cash flows and other 2,825 (4,838 ) 22,484 End of year (1) $ 592,700 $ 85,883 $ 104,396 (1) At December 31, 2017, the standardized measure of discounted future net cash flows includes $336.1 million attributable to noncontrolling interests.

Organization and Basis of Pre43

Organization and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Thousands	May 09, 2017USD ($)ClassOfStock$ / sharesshares	Oct. 31, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / shares	Sep. 05, 2017shares
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Common stock par value per share | $ / shares				$ 0.001	$ 0.001
Cash from sale of stock | $		$ 35,000	$ 47,100	$ 39,438	$ 47,125
EnCap, Oak Valley and Bold Holdings [Member] | Maximum [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Percentage of outstanding voting stock	20.00%
Class A Common Stock [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Common stock par value per share | $ / shares				$ 0.001	$ 0.001
Class B Common Stock [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Common stock par value per share | $ / shares				$ 0.001	$ 0.001
Bold Contribution Agreement [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Number of classes of common stock | ClassOfStock	2
Membership units issued in exchange				18,659
Stock conversion features	Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock.
Bold Contribution Agreement [Member] | Earthstone Energy Holdings, LLC [Member] | Bold Energy Holdings, LLC [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Membership units issued in exchange	36,070,828
Bold Contribution Agreement [Member] | Bold Energy Holdings, LLC [Member] | Earthstone Energy Holdings, LLC [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership interest				56.70%
Bold Contribution Agreement [Member] | Common Stock [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Common stock par value per share | $ / shares	$ 0.001
Bold Contribution Agreement [Member] | Lynden Energy Corporation [Member] | Earthstone Energy Holdings, LLC [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Membership units issued in exchange	5,865,328
Bold Contribution Agreement [Member] | Class A Common Stock [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Common stock par value per share | $ / shares	$ 0.001
Shares of common stock issued in arrangement	150,000
Closing sale price of common stock | $ / shares	$ 13.58
Bold Contribution Agreement [Member] | Class A Common Stock [Member] | 2014 Long Term Incentive Plan [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Shares of common stock issued in arrangement	150,000
Bold Contribution Agreement [Member] | Class A Common Stock [Member] | Earthstone Energy Holdings, LLC [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Stock conversion basis	one-for-one basis
Bold Contribution Agreement [Member] | Class A Common Stock [Member] | Bold Energy Holdings, LLC [Member] | Earthstone Energy Holdings, LLC [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership interest	61.40%
Bold Contribution Agreement [Member] | Class B Common Stock [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Common stock par value per share | $ / shares	$ 0.001
Cash from sale of stock | $	$ 36,000
Shares of common stock issued in arrangement						36,070,828
Stock conversion features				Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock.
Bold Contribution Agreement [Member] | Class B Common Stock [Member] | Bold Energy Holdings, LLC [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash from sale of stock | $	$ 36,071
Shares of common stock issued in arrangement	36,070,828
Bold Contribution Agreement [Member] | Class B Common Stock [Member] | Earthstone Energy Holdings, LLC [Member] | Bold Energy Holdings, LLC [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash from sale of stock | $	$ 36,071
Membership units issued in exchange	16,791,296

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Additional Information - (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)Contract	Dec. 31, 2018	Dec. 31, 2017USD ($)SegmentCustomerOperatorContract	Dec. 31, 2016USD ($)CustomerOperatorContract	Dec. 31, 2015USD ($)CustomerOperator
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts receivable | $	$ 200,000		$ 100,000	$ 200,000
Impairment of goodwill | $	$ 17,500,000		$ 0	$ 17,532,000	$ 1,547,000
Number of reportable segment | Segment			1
Number of major operators | Operator			1	1	1
Number of other operators accounted for 10% or more of revenue | Operator			0	0	0
Derivative asset, Number of derivative contracts | Contract	0		0	0
Liability for uncertain tax positions | $	$ 0		$ 0	$ 0	$ 0
Measurement period related to TCJA			1 year
Provisional income tax expense related to TCJA | $			$ 7,800,000
Scenario Forecast [Member]
Summary Of Significant Accounting Policies [Line Items]
Corporate income tax rate due to TCJA		21.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of major customer | Customer			3	2	1
Number of other customer accounted for 10% or more of revenues | Customer			0	0	0
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Customer One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			18.00%	41.00%	62.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Customer Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			14.00%	19.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Customer Three [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			14.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Operator One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			10.00%	19.00%	12.00%
Customer Concentration Risk [Member] | Accounts Receivable [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of major customer | Customer			3	2
Number of other customer accounted for 10% or more of receivables | Customer			0	0
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Customer Four [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			20.00%	28.00%
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Customer Five [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			13.00%	12.00%
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Customer Six [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			12.00%
Bold Contribution Agreement [Member] | Earthstone Energy Holdings Limited Liability Company And Lynden United States Incorporation [Member] | Earthstone Energy Holdings, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership interest held by Earthstone Energy, Inc. and Lynden US Inc.			43.30%
Bold Contribution Agreement [Member] | Bold Energy Holdings, LLC [Member] | Earthstone Energy Holdings, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership interest			56.70%

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Consideration Transferred, Fair Value of Assets Acquired and Liabilities Assumed (Details) - Bold Transaction [Member] $ / shares in Units, $ in Thousands	May 09, 2017USD ($)$ / sharesshares
Business Acquisition [Line Items]
Shares of common stock issued in arrangement | shares	36,220,828
Closing per share price of common stock | $ / shares	$ 13.58
Total consideration transferred	$ 491,879
Fair value of assets acquired:
Cash and cash equivalents	2,355
Other current assets	10,078
Oil and gas properties	557,704
Amount attributable to assets acquired	570,137
Fair value of liabilities assumed:
Long-term debt and Credit facility	58,000
Current liabilities	17,042
Deferred tax liability	2,857
Noncurrent asset retirement obligations	359
Amount attributable to liabilities assumed	$ 78,258
Class A Common Stock [Member]
Business Acquisition [Line Items]
Shares of common stock issued in arrangement | shares	150,000
Closing per share price of common stock | $ / shares	$ 13.58
Bold Energy III LLC [Member] | Certain Employees [Member] | Class A Common Stock [Member]
Business Acquisition [Line Items]
Shares of common stock issued in arrangement | shares	150,000
Bold Energy Holdings, LLC [Member]
Business Acquisition [Line Items]
Shares of common stock issued in arrangement | shares	36,070,828

Acquisitions and Divestitures46

Acquisitions and Divestitures - Schedule of Consideration Transferred, Fair Value of Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - Bold Transaction [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	May 09, 2017
Business Acquisition [Line Items]
Shares of common stock issued in arrangement		36,220,828
Closing per share price of common stock		$ 13.58
Stock conversion features	Each EEH Unit, together with one share of Class B Common Stock, is convertible into one share of Class A Common Stock.
Outstanding borrowings under credit agreement/facility		$ 58,000
Bold Energy Holdings, LLC [Member]
Business Acquisition [Line Items]
Shares of common stock issued in arrangement		36,070,828
Bold Energy Holdings, LLC [Member] | Earthstone Energy Holdings, LLC [Member]
Business Acquisition [Line Items]
Membership units issued in exchange		36,070,828
Class A Common Stock [Member]
Business Acquisition [Line Items]
Shares of common stock issued in arrangement		150,000
Closing per share price of common stock		$ 13.58
Class B Common Stock [Member]
Business Acquisition [Line Items]
Closing per share price of common stock		$ 13.58
Class B Common Stock [Member] | Bold Energy Holdings, LLC [Member]
Business Acquisition [Line Items]
Shares of common stock issued in arrangement		36,070,828

Acquisitions and Divestitures47

Acquisitions and Divestitures - Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Net loss	$ (44,733)	$ (54,541)	$ (116,655)
Bold Transaction [Member]
Business Acquisition [Line Items]
Revenue	126,839	54,436
Loss before taxes	(44,461)	(40,564)
Net loss	(35,617)	(41,092)
Less: Net loss attributable to noncontrolling interest	(22,005)	(27,012)
Net loss attributable to Earthstone Energy, Inc.	$ (13,612)	$ (14,080)
Pro forma net loss per common share attributable to Earthstone Energy, Inc.:
Basic and Diluted	$ (0.57)	$ (0.75)

Acquisitions and Divestitures48

Acquisitions and Divestitures - Additional Information (Details) - USD ($) $ in Thousands	Dec. 20, 2017	Dec. 31, 2017	Apr. 30, 2015	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Total cash consideration		$ 25,000			$ 34,735		$ 3,441
Gain on sale of oil and gas properties			$ 1,600		9,105	$ 8	$ 1,617
Effective date of transaction			Mar. 1, 2015
Cash consideration			$ 3,400
Non-core Properties [Member]
Business Acquisition [Line Items]
Total cash consideration					7,500
Gain on sale of oil and gas properties					6,100
Total cash consideration for eliminating of future abandonment obligations					$ 4,000
Williston Basin [Member]
Business Acquisition [Line Items]
Total cash consideration	$ 26,400
Normal and customary purchase price adjustments to account for net cash flows	900
Gain on sale of oil and gas properties	$ 3,000
Effective date of transaction	Dec. 1, 2017
Bold Transaction [Member]
Business Acquisition [Line Items]
Revenues				$ 50,200
Direct operating expenses				$ 23,800

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details)	Dec. 31, 2017USD ($)
Fair Value Disclosures [Abstract]
Fair value assets transfer from Level 1 to Level 2	$ 0
Fair value assets transfer from Level 2 to Level 1	0
Fair value liabilities transfer from Level 1 to Level 2	0
Fair value liabilities transfer from Level 2 to Level 1	$ 0

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Financial assets
Derivative asset- current	$ 184
Financial liabilities
Derivative liability - current	11,805	$ 4,595
Derivative liability - noncurrent	1,826	1,575
Fair Value on a Recurring Basis [Member]
Financial assets
Derivative asset- current	184
Total financial assets	184
Financial liabilities
Derivative liability - current	11,805	4,595
Derivative liability - noncurrent	1,826	1,575
Total financial liabilities	13,631	6,170
Level 2 [Member] | Fair Value on a Recurring Basis [Member]
Financial assets
Derivative asset- current	184
Total financial assets	184
Financial liabilities
Derivative liability - current	11,805	4,595
Derivative liability - noncurrent	1,826	1,575
Total financial liabilities	$ 13,631	$ 6,170

Derivative Financial Instrume51

Derivative Financial Instruments - Schedule of Outstanding Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2017MMBTU$ / MMBTUbbl
2018 | Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Volume | MMBTU	810,000
Price	3.066
2018 | Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Volume | bbl	1,483,250
Price	51.38
2018 | Crude Oil [Member] | Basis Swap [Member]
Derivative [Line Items]
Volume | bbl	602,250
Price	0.15
2019 | Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Volume | bbl	547,500
Price	52.32

Derivative Financial Instrume52

Derivative Financial Instruments - Additional Information (Details) - Subsequent Event [Member]	1 Months Ended
	Jan. 31, 2018$ / MMBTU$ / bblbbl
Derivative [Line Items]
Volume	365,000
Weighted Average Price | $ / bbl	58.38
Natural Gas Swap Agreements [Member]
Derivative [Line Items]
Volume	1,552,000
Weighted Average Price | $ / MMBTU	2.96

Derivative Financial Instrume53

Derivative Financial Instruments - Schedule of Location and Fair Value Amounts of All Derivative Instruments (Details) - Derivatives Not Designated as Hedging Contracts [Member] - Commodity Contracts [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Asset - Current [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Assets	$ 184
Total financial assets	184
Derivative Liability - Current [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Liabilities	11,805	$ 4,595
Total financial liabilities	11,805	4,595
Derivative Liability - Noncurrent [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Liabilities	1,826	1,575
Total financial liabilities	$ 1,826	$ 1,575

Derivative Financial Instrume54

Derivative Financial Instruments - Summary of Realized and Unrealized Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments Gain Loss [Line Items]
Cash settlements on commodity contracts	$ 708	$ (3,225)	$ (6,306)
(Loss) gain on commodity contracts, net	(7,986)	(6,638)	6,431
Derivatives Not Designated as Hedging Contracts [Member] | (Loss) Gain On Derivative Contracts, Net [Member]
Derivative Instruments Gain Loss [Line Items]
Total (loss) gain on commodity contracts	(7,278)	(9,863)	125
Cash settlements on commodity contracts	$ (708)	$ 3,225	$ 6,306

Oil and Natural Gas Propertie55

Oil and Natural Gas Properties - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Natural Gas Properties [Line Items]
Accumulated impairments to proved and unproved oil and natural gas properties	$ 148.2	$ 162.7
Proved Oil and Natural Gas Properties [Member]
Oil And Natural Gas Properties [Line Items]
Depletion expenses	$ 36.4	$ 25.4	$ 30.7
Unproved Oil and Gas Properties [Member] | Minimum [Member]
Oil And Natural Gas Properties [Line Items]
Unproved oil and gas lease term	3 years
Unproved Oil and Gas Properties [Member] | Maximum [Member]
Oil And Natural Gas Properties [Line Items]
Unproved oil and gas lease term	5 years

Oil and Natural Gas Propertie56

Oil and Natural Gas Properties - Schedule of Non-Cash Asset Impairment Charges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Impairment Charges [Line Items]
Asset impairment charges	$ 72,191	$ 6,751	$ 136,539
Proved Property [Member]
Asset Impairment Charges [Line Items]
Asset impairment charges	63,131	2,873	93,984
Unproved Property [Member]
Asset Impairment Charges [Line Items]
Asset impairment charges	$ 9,060	$ 3,878	$ 42,555

Goodwill - Additional Informati

Goodwill - Additional Information (Detail) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment of goodwill	$ 17,500,000	$ 0	$ 17,532,000	$ 1,547,000
Accumulated impairments to goodwill	$ 19,100,000	$ 19,100,000	$ 19,100,000

Goodwill - Summary of Non-Cash

Goodwill - Summary of Non-Cash Impairment Charges to Goodwill - (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment of goodwill	$ 17,500,000	$ 0	$ 17,532,000	$ 1,547,000

Noncontrolling Interest - Addit

Noncontrolling Interest - Additional Information (Details) - Bold Transaction [Member] - Earthstone Energy Holdings, LLC [Member]	May 09, 2017
Noncontrolling Interest [Line Items]
Percentage of ownership interest	61.40%
Earthstone Energy Holdings Limited Liability Company And Lynden US [Member]
Noncontrolling Interest [Line Items]
Percentage of ownership interest held by Earthstone Energy, Inc. and Lynden US Inc.	38.60%
Bold Holdings [Member]
Noncontrolling Interest [Line Items]
Percentage of ownership interest	61.40%

Noncontrolling Interest - Recon

Noncontrolling Interest - Reconciliation of Equity Attributable to Noncontrolling Interest (Details) - USD ($) $ in Thousands	May 09, 2017	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Portion of equity attributable to noncontrolling interest		$ 446,558
Bold Transaction [Member]
Noncontrolling Interest [Line Items]
Total consideration transferred	$ 491,879
Change to additional paid-in capital to reflect the noncontrolling interest within equity at their membership interest	(12,872)
Portion of equity attributable to noncontrolling interest	$ 479,007	$ 446,558

Noncontrolling Interest - Rec61

Noncontrolling Interest - Reconciliation of Equity Attributable to Noncontrolling Interest (Parenthetical) (Details)	May 09, 2017
Bold Transaction [Member] | Earthstone Energy Holdings, LLC [Member]
Noncontrolling Interest [Line Items]
Percentage of ownership interest	61.40%

Noncontrolling Interest - Summa

Noncontrolling Interest - Summary of Changes in Noncontrolling Interest (Details) - shares	May 09, 2017	Oct. 31, 2017	Jun. 30, 2016	Dec. 31, 2017
Noncontrolling Interest [Line Items]
As of December 31, 2016				22,273,820
EEH Units issued in connection with Class A Common Stock offering			4,753,770
As of December 31, 2017				0
Class A Common Stock [Member]
Noncontrolling Interest [Line Items]
As of December 31, 2016				0
As of December 31, 2017				27,584,638
Class A Common Stock [Member] | Stock Offering [Member]
Noncontrolling Interest [Line Items]
EEH Units issued in connection with Class A Common Stock offering		4,500,000
Earthstone Energy Holdings, LLC [Member]
Noncontrolling Interest [Line Items]
As of December 31, 2017				63,636,807
Earthstone Energy Holdings, LLC [Member] | Class A Common Stock [Member]
Noncontrolling Interest [Line Items]
EEH Units issued in connection with the vesting of restricted stock units and issuance of Class A Common Stock				259,355
Earthstone Energy Holdings, LLC [Member] | Class A Common Stock [Member] | Stock Offering [Member]
Noncontrolling Interest [Line Items]
EEH Units issued in connection with Class A Common Stock offering				4,500,000
Earthstone Energy Holdings, LLC [Member] | Bold Transaction [Member]
Noncontrolling Interest [Line Items]
Stock issued in connection with Bold Transaction	58,727,452
Earthstone Energy Holdings, LLC [Member] | Bold Transaction [Member] | Class A Common Stock [Member]
Noncontrolling Interest [Line Items]
Stock issued in connection with Bold Transaction				150,000
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Earthstone and Lynden [Member]
Noncontrolling Interest [Line Items]
As of December 31, 2017				27,584,638
Percentage of EEH Units Held By Earthstone and Lynden	38.60%			43.30%
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Earthstone and Lynden [Member] | Class A Common Stock [Member]
Noncontrolling Interest [Line Items]
EEH Units issued in connection with the vesting of restricted stock units and issuance of Class A Common Stock				259,355
Class B Common Stock converted to Class A Common Stock, shares				18,659
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Earthstone and Lynden [Member] | Class A Common Stock [Member] | Stock Offering [Member]
Noncontrolling Interest [Line Items]
EEH Units issued in connection with Class A Common Stock offering				4,500,000
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Earthstone and Lynden [Member] | Bold Transaction [Member]
Noncontrolling Interest [Line Items]
Stock issued in connection with Bold Transaction	22,656,624
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Earthstone and Lynden [Member] | Bold Transaction [Member] | Class A Common Stock [Member]
Noncontrolling Interest [Line Items]
Stock issued in connection with Bold Transaction				150,000
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Others [Member]
Noncontrolling Interest [Line Items]
As of December 31, 2017				36,052,169
Percentage of EEH Units Held By Others	61.40%			56.70%
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Others [Member] | Class A Common Stock [Member]
Noncontrolling Interest [Line Items]
Class B Common Stock converted to Class A Common Stock, shares				(18,659)
Earthstone Energy Holdings, LLC [Member] | EEH Units Held By Others [Member] | Bold Transaction [Member]
Noncontrolling Interest [Line Items]
Stock issued in connection with Bold Transaction	36,070,828

Noncontrolling Interest - Sum63

Noncontrolling Interest - Summary of Activity for Equity Attributable to Noncontrolling Interest (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Noncontrolling Interest [Line Items]
Net loss attributable to noncontrolling interest	$ (32,219)
As of December 31, 2017	446,558
Class A Common Stock [Member]
Noncontrolling Interest [Line Items]
Class B Common Stock converted to Class A Common Stock	(230)
Bold Transaction [Member]
Noncontrolling Interest [Line Items]
Noncontrolling interest recorded within equity in connection with the closing of the Bold Transaction	479,007
Net loss attributable to noncontrolling interest	(32,219)
As of December 31, 2017	$ 446,558

Net Loss Per Common Share - Rec

Net Loss Per Common Share - Reconciliation of Net Loss Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Net loss attributable to Earthstone Energy, Inc.	$ 2,324	$ 1,556	$ (17,123)	$ 729	$ (33,048)	$ (3,900)	$ (11,172)	$ (6,421)	$ (12,514)	$ (54,541)	$ (116,655)
Net loss per common share attributable to Earthstone Energy, Inc.:
Basic									$ (0.53)	$ (2.92)	$ (8.43)
Diluted									$ (0.53)	$ (2.92)	$ (8.43)
Weighted average common shares outstanding
Basic									23,589,973	18,651,582	13,835,128
Add potentially dilutive securities:
Diluted weighted average common shares outstanding									23,589,973	18,651,582	13,835,128

Net Loss Per Common Share - Add

Net Loss Per Common Share - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Net loss attributable to noncontrolling interest	$ (32,219,000)
Dilutive effect on Net loss per common share attributable to Earthstone Energy, Inc	$ 0
Restricted Stock Units [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Dilutive effect of restricted stock units excluded from calculating diluted earnings per share	105,422	52,844
Restricted Stock Units [Member] | 2014 Long Term Incentive Plan [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares issued			0
Shares outstanding			0
Earthstone Energy, Inc [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Net loss attributable to noncontrolling interest	$ (32,200,000)

Common Stock - Additional Infor

Common Stock - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 02, 2017	May 09, 2017	May 18, 2016	Oct. 31, 2017	Jun. 30, 2016	May 08, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Sep. 05, 2017
Capital Unit [Line Items]
Common stock, shares issued							0	0	22,289,177
Common stock, shares outstanding							0	0	22,273,820
Common stock shares issued upon completion of public offering					4,753,770
Shares issued, price per share					$ 10.50
Cash from sale of stock				$ 35,000	$ 47,100			$ 39,438	$ 47,125
Stock issuance costs					$ 2,700			$ 2,200	$ 2,700
Bold Contribution Agreement [Member]
Capital Unit [Line Items]
Stock conversion features		Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock.
Membership units issued in exchange							18,659	18,659
Common Stock [Member]
Capital Unit [Line Items]
Common stock shares issued upon completion of public offering									4,753,770
Restricted Stock Units [Member] | 2014 Plan [Member] | Common Stock [Member]
Capital Unit [Line Items]
Common stock shares issued upon vesting and settlement						382,804
Class A Common Stock [Member]
Capital Unit [Line Items]
Common stock, shares issued							27,584,638	27,584,638	0
Common stock, shares outstanding							27,584,638	27,584,638	0
Treasury stock, shares, retired	15,357
Class A Common Stock [Member] | Stock Offering [Member]
Capital Unit [Line Items]
Common stock shares issued upon completion of public offering				4,500,000
Shares issued, price per share				$ 9.25
Cash from sale of stock				$ 39,400
Stock issuance costs				$ 2,200
Class A Common Stock [Member] | Bold Contribution Agreement [Member]
Capital Unit [Line Items]
Shares of common stock issued in arrangement		150,000
Common stock issued		$ 2,000						$ 2,037
Class A Common Stock [Member] | Bold Contribution Agreement [Member] | Earthstone Energy Holdings, LLC [Member]
Capital Unit [Line Items]
Stock conversion basis		one-for-one basis
Class B Common Stock converted to Class A Common Stock, shares								18,659
Class A Common Stock [Member] | Common Stock [Member]
Capital Unit [Line Items]
Treasury stock, shares, retired								(76,412)
Shares withheld by Company in exchange for payment of income tax withholdings								61,055
Common stock shares issued upon completion of public offering								4,500,000
Class B Common Stock converted to Class A Common Stock, shares								18,659
Class A Common Stock [Member] | 2014 Plan [Member]
Capital Unit [Line Items]
Shares withheld by Company in exchange for payment of income tax withholdings							61,055
Class A Common Stock [Member] | 2014 Plan [Member] | Bold Contribution Agreement [Member]
Capital Unit [Line Items]
Shares of common stock issued in arrangement		150,000
Class A Common Stock [Member] | Restricted Stock Units [Member] | 2014 Plan [Member]
Capital Unit [Line Items]
Common stock shares issued upon vesting and settlement							320,410
Class B Common Stock [Member]
Capital Unit [Line Items]
Common stock, shares issued							36,052,169	36,052,169	0
Common stock, shares outstanding							36,052,169	36,052,169	0
Class B Common Stock [Member] | Bold Contribution Agreement [Member]
Capital Unit [Line Items]
Shares of common stock issued in arrangement										36,070,828
Common stock issued								$ 489,842
Cash from sale of stock		$ 36,000
Stock conversion features								Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock.
Class B Common Stock converted to Class A Common Stock, shares								(18,659)
Class B Common Stock [Member] | Common Stock [Member]
Capital Unit [Line Items]
Class B Common Stock converted to Class A Common Stock, shares								(18,659)
Reverse acquisition, shares								36,070,828
Bold Transaction [Member]
Capital Unit [Line Items]
Common stock issued		$ 491,879
Bold Transaction [Member] | Class A Common Stock [Member]
Capital Unit [Line Items]
Stock conversion basis								one-for-one basis
Lynden Arrangement [Member]
Capital Unit [Line Items]
Common stock issued									$ 45,699
Lynden Arrangement [Member] | Common Stock [Member]
Capital Unit [Line Items]
Common stock issued			$ 45,700
Reverse acquisition, shares			3,700,279						3,700,279

Stock Based Compensation - Addi

Stock Based Compensation - Additional Information (Details) - Restricted Stock Units [Member] - USD ($)	May 09, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted		949,000
Shares granted, Weighted average grant date fair value		$ 9.80
2014 Long Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted				0
Grant date fair value of units granted		$ 9,800,000	$ 9,300,000
Shares granted, Weighted average grant date fair value		$ 9.80	$ 12.53
Vesting date fair value of units vested		$ 8,300,000	$ 0	$ 0
Unrecognized compensation expense related to unvested stock		$ 8,400,000
Weighted average remaining vesting period of unrecognized compensation expense		10 months 28 days
Stock-based compensation expense		$ 6,600,000	$ 3,300,000	$ 0
2014 Long Term Incentive Plan [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		12 months
2014 Long Term Incentive Plan [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		36 months
2014 Long Term Incentive Plan [Member] | Employees [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted		910,000
2014 Long Term Incentive Plan [Member] | Board of Directors [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted		39,000
2014 Long Term Incentive Plan [Member] | Bold Contribution Agreement [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares authorized to be issued under the plan	5,800,000
2014 Long Term Incentive Plan [Member] | Class A Common Stock [Member] | Bold Contribution Agreement [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Increase in number of shares authorized to be issued under the plan	4,300,000
Number of shares of common stock that each holder has contingent right to receive	1

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Unvested RSU Award Activity (Details) - Restricted Stock Units [Member]	12 Months Ended
	Dec. 31, 2017$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested RSUs at beginning period, share | shares	781,500
Granted, Shares | shares	949,000
Forfeited, Shares | shares	(58,041)
Vested, Shares | shares	(703,214)
Unvested RSUs at end period, share | shares	969,245
Unvested RSUs at beginning of period, Weighted-Average Grant Date Fair Value | $ / shares	$ 12.53
Granted, Weighted-Average Grant Date Fair Value | $ / shares	9.80
Forfeited, Weighted-Average Grant Date Fair Value | $ / shares	12.98
Vested, Weighted-Average Grant Date Fair Value | $ / shares	12.44
Unvested RSUs at end of period, Weighted-Average Grant Date Fair Value | $ / shares	$ 9.89

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Details) - USD ($) $ in Thousands	May 09, 2017	Dec. 31, 2017	Oct. 31, 2017	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 31, 2016
Debt Instrument [Line Items]
Long-term debt		$ 25,000			$ 25,000	$ 12,693
Amount of Borrowings		85,000			85,000
Repayments of borrowings					74,298	38,549
Proceeds received from common stock			$ 35,000	$ 47,100	39,438	47,125
Proceeds received from sale of assets		25,000			34,735		$ 3,441
Amortization of deferred financing costs					257	298	264
Unsecured Promissory Note [Member]
Debt Instrument [Line Items]
Debt instrument, principal amount								$ 5,100
Bold Transaction [Member]
Debt Instrument [Line Items]
Repayments of borrowings					58,000
Bold Transaction [Member] | Four Year Senior Secured Revolving Credit Facility [member]
Debt Instrument [Line Items]
Repayments of borrowings	$ 10,000
EEH Credit Agreement [Member]
Debt Instrument [Line Items]
Current borrowing base under EEH credit agreement	$ 185,000	185,000			$ 185,000
Commitment fee percentage	0.50%
Debt outstanding maturity	May 9, 2022
Line of credit facility, covenant terms					In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio 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.
Long-term debt		$ 25,000			$ 25,000
Long-term debt, percentage bearing annual interest rate		3.7611%			3.7611%
Additional borrowing base available under credit agreement		$ 160,000			$ 160,000
Commitment fees on borrowings					300	300	300
Amortization of deferred financing costs					$ 300	$ 300	$ 300
EEH Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage	2.25%
EEH Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage	3.25%
EEH Credit Agreement [Member] | Prime Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage	1.25%
EEH Credit Agreement [Member] | Prime Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage	2.25%
Earthstone Energy Credit Agreement [Member]
Debt Instrument [Line Items]
Averaged interest rate on outstanding debt					4.26%	4.03%	1.68%
Capitalized costs associated with borrowings					$ 1,400	$ 100	$ 100
Write-off of Deferred Financing Costs [Member] | Bold Transaction [Member] | Four Year Senior Secured Revolving Credit Facility [member]
Debt Instrument [Line Items]
Remaining unamortized deferred financing costs	$ 500

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total debt	$ 25,000	$ 14,297
Less: Current portion of long-term debt		(1,604)
Long-term debt	25,000	12,693
Promissory Note [Member]
Debt Instrument [Line Items]
Total debt		4,297
Credit Agreement [Member]
Debt Instrument [Line Items]
Total debt	$ 25,000	$ 10,000

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Asset Retirement Obligation Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning asset retirement obligations	$ 6,013	$ 5,075
Liabilities acquired	359	250
Liabilities incurred	77	165
Property dispositions	(4,401)
Liabilities settled	(9)	(15)
Accretion expense	434	551	$ 550
Revision of estimates	(119)	(13)
Ending asset retirement obligations	$ 2,354	$ 6,013	$ 5,075

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Flatonia Energy, LLC [Member] - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Payments made to related party	$ 26,500,000	$ 26,600,000	$ 33,900,000
Payments received from related party	5,400,000	21,700,000	$ 66,700,000
Amounts receivable due from related party	1,300,000	1,500,000
Amounts payable due to related party	$ 0	$ 3,100,000
Class A Common Stock [Member]
Related Party Transaction [Line Items]
Percentage of common stock acquired	10.70%

Commitment and Contingencies -

Commitment and Contingencies - Future Minimum Contractual Commitments under Non-cancelable Agreements (Details) $ in Thousands	Dec. 31, 2017USD ($)
Operating Leased Assets [Line Items]
2,018	$ 2,497
2,019	2,366
2,020	1,647
2,021	680
Gas Contract [Member]
Operating Leased Assets [Line Items]
2,018	1,643
2,019	1,643
2,020	1,647
2,021	680
Office Leases [Member]
Operating Leased Assets [Line Items]
2,018	854
2,019	$ 723

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Thousands	Aug. 18, 2017USD ($)Property	Dec. 31, 2017USD ($)MMBTU	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Non-cancelable fixed cost agreement, 2018		$ 2,497
Non-cancelable fixed cost agreement, 2019		2,366
Non-cancelable fixed cost agreement, 2020		1,647
Non-cancelable fixed cost agreement, 2021		680
Rent expense		900	$ 800	$ 800
Trinity Royal Partners, LP
Loss Contingencies [Line Items]
Number of properties under litigation case | Property	2
Damages and attorneys’ fees sought by plaintiff	$ 7,200
Non-cancelable Agreement [Member]
Loss Contingencies [Line Items]
Non-cancelable fixed cost agreement, 2018		1,600
Non-cancelable fixed cost agreement, 2019		1,600
Non-cancelable fixed cost agreement, 2020		1,600
Non-cancelable fixed cost agreement, 2021		$ 1,600
Holding pipeline capacity | MMBTU		10,000

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
State	$ (15)		$ (91)
Total current	(15)		(91)
Deferred:
Federal	16,186	$ (515)	26,214
State	202	(13)	319
Total deferred	16,388	(528)	26,533
Total income tax benefit (provision)	$ 16,373	$ (528)	$ 26,442

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Effective Tax Rate to Statutory Rate (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation Of Income Tax Rate [Line Items]
Net loss before income taxes	$ (61,106)	$ (54,013)	$ (143,097)
Tax benefit computed at statutory rate	(20,776)	(18,365)	(48,653)
Noncontrolling interest	12,118
Non-deductible impairment of goodwill		5,961
Non-deductible transaction costs		878
Non-deductible general and administrative expenses	168	5	534
Return to accrual	(486)	15	(1,398)
State income taxes, net of Federal benefit	(191)	(128)	(743)
Valuation allowance	(15,477)	12,162	23,818
Federal rate change	7,824
State rate change	445
Rate differential on Canadian activity	2
Total income tax (benefit) expense	$ (16,373)	$ 528	$ (26,442)
Effective tax rate	26.80%	(1.00%)	18.50%
U.S. [Member]
Reconciliation Of Income Tax Rate [Line Items]
Net loss before income taxes	$ (61,082)	$ (54,032)
Statutory rate	34.00%	34.00%
Tax benefit computed at statutory rate	$ (20,768)	$ (18,370)
Noncontrolling interest	12,118
Non-deductible impairment of goodwill		5,961
Non-deductible transaction costs		878
Non-deductible general and administrative expenses	168	5
Return to accrual	(486)	15
State income taxes, net of Federal benefit	(191)	(128)
Valuation allowance	(15,483)	12,167
Federal rate change	7,824
State rate change	445
Total income tax (benefit) expense	$ (16,373)	$ 528
Effective tax rate	26.80%	(1.00%)
Canada [Member]
Reconciliation Of Income Tax Rate [Line Items]
Net loss before income taxes	$ (24)	$ 19
Statutory rate	26.00%	26.00%
Tax benefit computed at statutory rate	$ (8)	$ 5
Valuation allowance	6	$ (5)
Rate differential on Canadian activity	$ 2
Effective tax rate	0.00%	0.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Line Items]
Income tax benefit (expense)		$ 16,373	$ (528)	$ 26,442
Measurement period related to TCJA		1 year
Provisional income tax expense related to TCJA		$ 7,800
Effective tax rate		26.80%	(1.00%)	18.50%
Valuation allowance		$ (15,477)	$ 12,162	$ 23,818
Non-deductible impairment of goodwill			5,961
Valuation allowance		(24,120)	(39,596)
Net deferred noncurrent tax assets		13,605	23,820
Deferred tax liabilities		10,515	15,776
U.S. [Member]
Income Tax Disclosure [Line Items]
Income tax benefit (expense)		$ 16,373	$ (528)
Corporate income tax rate due to TCJA		34.00%	34.00%
Effective tax rate		26.80%	(1.00%)
Valuation allowance		$ (15,483)	$ 12,167
Non-deductible impairment of goodwill			5,961
Deferred tax assets		20,500	36,000
Deferred tax liabilities		8,500	$ 15,800
Operating loss carryforward, net		$ 49,100
Net operating loss carryforwards expire beginning year		2,034
Net operating loss carryforwards expire ending year		2,037
Canada [Member]
Income Tax Disclosure [Line Items]
Corporate income tax rate due to TCJA		26.00%	26.00%
Effective tax rate		0.00%	0.00%
Valuation allowance		$ 6	$ (5)
Deferred tax assets		3,600	$ 3,600
Operating loss carryforward, net		$ 10,000
Net operating loss carryforwards expire beginning year		2,024
Net operating loss carryforwards expire ending year		2,036
Scenario Plan [Member]
Income Tax Disclosure [Line Items]
Corporate income tax rate due to TCJA	21.00%
Lynden Energy Corporation [Member]
Income Tax Disclosure [Line Items]
Income tax benefit due to TCJA		$ 8,600
Change in deferred tax liability due to TCJA		4,800
Lynden Arrangement [Member] | U.S. [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforward, net		28,000
Earthstone Energy Holdings, LLC [Member]
Income Tax Disclosure [Line Items]
Income tax benefit due to TCJA		7,700
Change in deferred tax asset due to TCJA		$ 12,600

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred noncurrent income tax assets (liabilities):
Office and other equipment		$ (48)
Oil & gas properties	$ 2,998	7,428
Asset retirement obligation		2,042
Basis difference in subsidiary obligation	(2,268)	(4,226)
Intangible assets		36
Unrealized derivative loss		2,145
Stock-based compensation		1,148
Investment in Partnerships	(111)
Federal net operating loss carryforward	12,986	15,109
Other		186
Net deferred noncurrent tax assets	13,605	23,820
Valuation allowance	(24,120)	(39,596)
Net deferred tax liability	$ (10,515)	$ (15,776)

Profit Sharing Plan - Additiona

Profit Sharing Plan - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, maximum annual contributions per employee, percent	100.00%
Defined contribution plan, employer contribution amount	$ 0.3
Maximum [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, employer matching contribution, percent of match	6.00%

Supplemental Selected Quarter80

Supplemental Selected Quarterly Financial Data (Unaudited) - Schedule of Supplemental Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Oil and gas revenues	$ 35,676	$ 31,282	$ 25,777	$ 15,343	$ 15,152	$ 10,530	$ 9,777	$ 6,810
(Loss) income from operations	12,105	8,546	(67,093)	(3,433)	(28,436)	(4,316)	(6,433)	(6,836)	$ (49,875)	$ (46,021)	$ (149,229)
Net income (loss) attributable to Earthstone Energy, Inc.	$ 2,324	$ 1,556	$ (17,123)	$ 729	$ (33,048)	$ (3,900)	$ (11,172)	$ (6,421)	$ (12,514)	$ (54,541)	$ (116,655)
Net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic and diluted	$ 0.09	$ 0.07	$ (0.75)	$ 0.03	$ (1.48)	$ (0.17)	$ (0.69)	$ (0.46)

Supplemental Selected Quarter81

Supplemental Selected Quarterly Financial Data (Unaudited) - Additional Information (Details) - USD ($)	3 Months Ended			12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Impairment expense	$ 66,600,000	$ 6,800,000		$ 72,191,000	$ 24,283,000	$ 138,086,000
Impairment of goodwill		$ 17,500,000		$ 0	$ 17,532,000	$ 1,547,000
Termination of drilling rig			$ 5,100,000

Supplemental Information On O82

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Costs Incurred Related to Oil and Gas Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition cost:
Proved	$ 315,376	$ 48,116	$ 4,508
Unproved	245,589	26,600	10,646
Exploration costs:
Geological and geophysical	1	5	142
Development costs	77,876	28,577	56,862
Total additions	$ 638,842	$ 103,298	$ 72,158

Supplemental Information On O83

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Apr. 30, 2015	Dec. 31, 2017USD ($)MMBTUMBoeWell$ / MMBTU$ / bbl	Dec. 31, 2016USD ($)MBoe$ / MMBTU$ / bbl	Dec. 31, 2015USD ($)MBoe$ / MMBTU$ / bbl
Reserve Quantities [Line Items]
Additions to oil and gas properties | $		$ 638,842,000	$ 103,298,000	$ 72,158,000
Capitalized exploratory well costs | $		$ 0	$ 0	$ 0
Natural gas liquids prices used to value reserves | $ / bbl		22.59	13.21	14.11
Proved extensions and discoveries		30,763	423	685
Effective date of transaction	Mar. 1, 2015
Sales of minerals in place		2,976		1,344
Purchases of minerals in place		45,911	10,647	1,962
Revision to previous estimates		2,901	10,128	9,484
Revisions		4,832	2,268	9,340
Improved proved developed reserves		1,931
Removal of proved undeveloped reserves		2,011
Excepted completion period of development plans		5 years
Conversion period of proved undeveloped reserves into proved developed producing reserves		5 years	5 years
Estimated capital expenditures of proved undeveloped reserves | $		$ 6,900,000	$ 3,100,000
Capital expenditures of proved undeveloped reserves | $		$ 8,500,000	$ 3,200,000
Estimated conversion of proved undeveloped reserves into proved developed producing reserves		732	258
Conversion of proved undeveloped reserves into proved developed producing reserves		2,756	169	1,700
Sales of minerals in place		(391)
Extensions and discoveries		27,977	293	685
Modified conversion of proved undeveloped reserves into proved developed producing reserves		622
Non-cancelable Agreement [Member]
Reserve Quantities [Line Items]
Holding pipeline capacity | MMBTU		10,000
Eagle Ford Property [Member]
Reserve Quantities [Line Items]
Purchases of minerals in place				1,962
Proved undeveloped reserves excepted volume to be developed		443
Bold Transaction [Member]
Reserve Quantities [Line Items]
Reduction of proved undeveloped reserves		2,378
Capital expenditures of proved undeveloped reserves | $		$ 63,400,000
Conversion of proved undeveloped reserves into proved developed producing reserves		2,134
Added to proved undeveloped reserves		37,327
Midland Basin [Member]
Reserve Quantities [Line Items]
Proved extensions and discoveries		30,763
Sales of minerals in place		391
Extensions and discoveries		27,977
Midland Basin [Member] | Bold Transaction [Member]
Reserve Quantities [Line Items]
Effective date of transaction		May 9, 2017
Purchases of minerals in place		45,911
Producing oil and gas wells | Well		63
Proved developed non-producing wells | Well		4
Williston Basin [Member]
Reserve Quantities [Line Items]
Sales of minerals in place		2,976
Henry Hub Spot Price [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas | $ / MMBTU		2.98	2.48	2.59
West Texas Intermediate Spot Price [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil | $ / bbl		51.34	42.75	50.28
New Wells [Member]
Reserve Quantities [Line Items]
Additions to oil and gas properties | $		$ 100,000	$ 200,000	$ 200,000
Operated Eagle Ford and Non-operated Bakken Properties [Member]
Reserve Quantities [Line Items]
Proved extensions and discoveries			423	685
Non-operated Midland Basin Properties [Member] | Lynden Arrangement [Member]
Reserve Quantities [Line Items]
Purchases of minerals in place			10,647
Louisiana Properties [Member]
Reserve Quantities [Line Items]
Sales of minerals in place				1,344

Supplemental Information On O84

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Summary of Capitalized Costs, Impairment, and Depreciation, Depletion and Amortization (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and gas properties, successful efforts method:
Accumulated impairment	$ (148,200)	$ (162,700)
Proved properties, net of accumulated impairments	605,039	363,072
Unproved properties, net of accumulated impairments	275,025	51,723
Total oil and gas properties, net of accumulated impairments	885,598	414,795
Accumulated depreciation, depletion and amortization	(118,028)	(145,393)
Net oil and gas properties	767,570	269,402
Proved Property [Member]
Oil and gas properties, successful efforts method:
Proved properties	714,180	476,832
Accumulated impairment	(103,608)	(113,760)
Proved properties, net of accumulated impairments	610,572	363,072
Unproved Property [Member]
Oil and gas properties, successful efforts method:
Unproved properties	319,569	100,612
Accumulated impairment	(44,543)	(48,889)
Unproved properties, net of accumulated impairments	$ 275,026	$ 51,723

Supplemental Information On O85

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Changes in Quantities of Proved Oil and natural Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf
Reserve Quantities [Line Items]
Beginning balance | MBoe	12,051	12,574	22,192
Extensions and discoveries | MBoe	30,763	423	685
Sales of minerals in place | MBoe	(2,976)		(1,344)
Purchases of minerals in place | MBoe	45,911	10,647	1,962
Production | MBoe	(2,872)	(1,465)	(1,437)
Revision to previous estimates | MBoe	(2,901)	(10,128)	(9,484)
Ending Balance | MBoe	79,976	12,051	12,574
Proved developed reserves | MBoe	19,961	9,361	8,613	9,800
Proved undeveloped reserves | MBoe	60,015	2,690	3,961	12,392
Crude Oil [Member]
Reserve Quantities [Line Items]
Beginning balance	7,111	9,361	13,803
Extensions and discoveries	19,558	345	526
Sales of minerals in place	(1,833)		(4)
Purchases of minerals in place	28,176	5,548	1,641
Production	(1,828)	(878)	(904)
Revision to previous estimates	(3,857)	(7,265)	(5,701)
Ending balance	47,327	7,111	9,361
Proved developed reserves	11,949	6,052	6,114	6,093
Proved undeveloped reserves	35,378	1,059	3,247	7,710
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance | MMcf	20,401	13,338	38,579
Extensions and discoveries | MMcf	29,644	285	828
Sales of minerals in place | MMcf	(6,853)		(8,040)
Purchases of minerals in place | MMcf	46,709	14,770	679
Production | MMcf	(3,260)	(2,171)	(2,143)
Revision to previous estimates | MMcf	4,447	(5,821)	(16,565)
Ending Balance | MMcf	91,088	20,401	13,338
Proved developed reserves | MMcf	23,336	13,545	10,954	16,214
Proved undeveloped reserves | MMcf	67,752	6,856	2,384	22,365
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning balance	1,540	990	1,959
Extensions and discoveries	6,264	30	21
Sales of minerals in place	(1)
Purchases of minerals in place	9,950	2,637	208
Production	(500)	(225)	(176)
Revision to previous estimates	215	(1,892)	(1,022)
Ending balance	17,468	1,540	990
Proved developed reserves	4,123	1,051	673	1,005
Proved undeveloped reserves	13,345	489	317	954

Supplemental Information On O86

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Changes in Quantities of Proved Oil and natural Gas Reserves (Parenthetical) (Details)	Dec. 31, 2017MMBblsBcf
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped oil reserves attributable to noncontrolling interests	26.8
Proved developed oil reserves attributable to noncontrolling interests	6.8
Proved undeveloped oil reserves attributable to noncontrolling interests	20
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped oil reserves attributable to noncontrolling interests | Bcf	51.6
Proved developed oil reserves attributable to noncontrolling interests | Bcf	13.2
Proved undeveloped oil reserves attributable to noncontrolling interests | Bcf	38.4
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped oil reserves attributable to noncontrolling interests	9.9
Proved developed oil reserves attributable to noncontrolling interests	2.3
Proved undeveloped oil reserves attributable to noncontrolling interests	7.6

Supplemental Information On O87

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule of Changes in Proved Undeveloped Reserves (Details) - MBoe	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Proved undeveloped reserves, Beginning Balance	2,690	3,961	12,392
Conversions to developed	(2,756)	(169)	(1,700)
Extensions and discoveries	27,977	293	685
Sales of minerals in place	(391)
Purchases of minerals in place	37,327	873	1,924
Revision to previous estimates	(4,832)	(2,268)	(9,340)
Proved undeveloped reserves, Ending Balance	60,015	2,690	3,961

Supplemental Information On O88

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule of Changes in Proved Undeveloped Reserves (Parenthetical) (Details)	Dec. 31, 2017MBoe
Extractive Industries [Abstract]
Proved undeveloped reserves attributable to noncontrolling interests	34,029

Supplemental Information On O89

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule Of Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Future cash inflows	$ 2,948,989	$ 346,948	$ 481,131
Future production costs	(757,716)	(172,062)	(192,349)
Future development costs	(677,093)	(29,814)	(91,725)
Future income tax expense	(33,644)
Future net cash flows	1,480,536	145,072	197,057
10% annual discount for estimated timing of cash flows	(887,836)	(59,189)	(92,661)
Standardized measure of discounted future net cash flows	$ 592,700	$ 85,883	$ 104,396	$ 255,856

Supplemental Information On O90

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule Of Standardized Measure (Parenthetical) (Details) $ in Millions	Dec. 31, 2017USD ($)
Extractive Industries [Abstract]
Standardized measure of discounted future net cash flows attributable to noncontrolling interest	$ 336.1

Supplemental Information On O91

Supplemental Information On Oil And Gas Exploration And Production Activities - Changes In Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Standardized Measure, beginning of year	$ 85,883	$ 104,396	$ 255,856
Sales of oil and gas produced, net of production costs	(81,926)	(24,998)	(29,152)
Sales of minerals in place	(15,553)		(2,470)
Net changes in prices and production costs	155,629	(102,143)	(288,064)
Extensions, discoveries, and improved recoveries	201,801	241	6,514
Changes in income taxes, net	(5,941)		88,944
Previously estimated development costs incurred during the period	76,447	27,770	26,977
Net changes in future development costs	(168,940)	102,267	6,697
Purchases of minerals in place	244,785	16,921	7,695
Revisions of previous quantity estimates	68,705	(45,239)	(16,671)
Accretion of discount	28,985	11,506	25,586
Changes in timing of estimated cash flows and other	2,825	(4,838)	22,484
Standardized Measure, end of year	$ 592,700	$ 85,883	$ 104,396

Supplemental Information On O92

Supplemental Information On Oil And Gas Exploration And Production Activities - Changes In Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves (Parenthetical) (Details) $ in Millions	Dec. 31, 2017USD ($)
Extractive Industries [Abstract]
Standardized measure of discounted future net cash flows attributable to noncontrolling interest	$ 336.1