Earthstone Energy (ESTE) 10-K 11 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 09, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
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 Common Stock, Shares Outstanding		13,835,128
Entity Public Float			$ 83,152,373

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 23,264,000	$ 100,447,000
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	13,529,000	14,016,000
Joint interest billings and other	4,924,000	9,417,000
Current derivative assets	3,694,000	3,569,000
Prepaid expenses and other current assets	498,000	1,578,000
Total current assets	45,909,000	129,027,000
Oil and gas properties, successful efforts method:
Proved properties	283,644,000	317,006,000
Unproved properties	34,609,000	76,791,000
Total oil and gas properties	318,253,000	393,797,000
Accumulated depreciation, depletion, and amortization	(119,920,000)	(97,920,000)
Net oil and gas properties	198,333,000	295,877,000
Other noncurrent assets:
Goodwill	17,532,000	22,992,000
Office and other equipment, less accumulated depreciation of $1,028 in 2015 and $474 in 2014	1,934,000	2,109,000
Land		101,000
Other noncurrent assets	1,236,000	1,282,000
TOTAL ASSETS	264,944,000	451,388,000
Current liabilities:
Accounts payable	11,580,000	28,753,000
Accrued expenses	12,975,000	20,529,000
Revenues and royalties payable	8,576,000	17,364,000
Advances	15,447,000	21,398,000
Asset retirement obligations	0	408,000
Total current liabilities	48,578,000	88,452,000
Noncurrent liabilities:
Long-term debt	11,191,000	11,191,000
Asset retirement obligations	5,075,000	5,670,000
Deferred tax liability		29,258,000
Other noncurrent liabilities	227,000	289,000
Total noncurrent liabilities	16,493,000	46,408,000
Total liabilities	$ 65,071,000	$ 134,860,000
Commitments and Contingencies (Note 12)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding
Common stock, $0.001 par value, 100,000,000 shares authorized; 13,835,128 shares issued and outstanding in 2015 and 2014	$ 14,000	$ 14,000
Additional paid-in capital	358,086,000	358,086,000
Accumulated deficit	(157,767,000)	(41,112,000)
Treasury stock, 15,357 shares in 2015 and 2014	(460,000)	(460,000)
Total equity	199,873,000	316,528,000
TOTAL LIABILITIES AND EQUITY	$ 264,944,000	$ 451,388,000

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Office and other equipment, accumulated depreciation	$ 1,028	$ 474
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	100,000,000	100,000,000
Common stock, shares issued	13,835,128	13,835,128
Common stock, shares outstanding	13,835,128	13,835,128
Treasury stock, shares	15,357	15,357

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil, natural gas, and natural gas liquids revenues:
Oil	$ 39,849	$ 34,734	$ 16,038
Natural gas	5,457	9,367	9,714
Natural gas liquids	2,158	3,510	3,882
Total oil, natural gas, and natural gas liquids revenues	47,464	47,611	29,634
Gathering income	309	383	430
Gain (loss) on sale of oil and gas properties	1,617		(121)
Total revenues	49,390	47,994	29,943
Production costs:
Lease operating expense	15,409	10,122	8,426
Severance taxes	2,582	2,002	1,225
Re-engineering and workovers	872	708	342
Impairment expense	138,086	19,359	12,298
Depreciation, depletion, and amortization	31,228	18,414	17,111
Exploration expense	142	111	2,490
General and administrative expense	10,300	7,864	7,751
Total operating costs and expenses	198,619	58,580	49,643
Income (loss) from operations	(149,229)	(10,586)	(19,700)
OTHER INCOME (EXPENSE)
Interest expense, net	(722)	(597)	(487)
Net gain on derivative contracts	6,431	4,392	296
Other income, net	423	62	16
Total other income (expense)	6,132	3,857	(175)
Loss before income taxes	(143,097)	(6,729)	(19,875)
Income tax (benefit) expense	(26,442)	22,105
Net income (loss)	$ (116,655)	$ (28,834)	$ (19,875)
Net loss per common share:
Basic	$ (8.43)	$ (3.11)	$ (2.18)
Diluted	$ (8.43)	$ (3.11)	$ (2.18)
Weighted average common shares outstanding:
Basic	13,835,128	9,279,324	9,124,452
Diluted	13,835,128	9,279,324	9,124,452

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Members' Equity [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Deficit [Member]	Treasury Stock [Member]	Oak Valley Resources, LLC [Member]	Oak Valley Resources, LLC [Member]Members' Equity [Member]	Oak Valley Resources, LLC [Member]Members' Equity [Member]Subsidiaries [Member]	Oak Valley Resources, LLC [Member]Common Stock [Member]	Oak Valley Resources, LLC [Member]Common Stock [Member]Subsidiaries [Member]	Oak Valley Resources, LLC [Member]Additional Paid-in Capital [Member]	Oak Valley Resources, LLC [Member]Additional Paid-in Capital [Member]Subsidiaries [Member]	Oak Valley Resources, LLC [Member]Treasury Stock [Member]	Eagle Ford [Member]	Eagle Ford [Member]Common Stock [Member]	Eagle Ford [Member]Additional Paid-in Capital [Member]
Beginning Balance, amount at Dec. 31, 2012	$ 61,267	$ 61,267
Contributions							$ 107,530	$ 107,530
Net income (loss)	(19,875)	(19,875)
Ending Balance, amount at Dec. 31, 2013	148,922	148,922
Contributions							107,020	$ 107,020	$ (268,220)		$ 9		$ 268,211
Contribution, shares											9,124,452
Reverse acquisition							$ 32,995			$ 2		$ 33,453		$ (460)	$ 56,425	$ 3	$ 56,422
Reverse acquisition, shares										1,753,388				(15,357)		2,957,288
Net income (loss)	(28,834)	$ 12,278			$ (41,112)
Ending Balance, amount at Dec. 31, 2014	316,528		$ 14	$ 358,086	(41,112)	$ (460)
Ending Balance, shares at Dec. 31, 2014			13,835,128			(15,357)
Net income (loss)	(116,655)				(116,655)
Ending Balance, amount at Dec. 31, 2015	$ 199,873		$ 14	$ 358,086	$ (157,767)	$ (460)
Ending Balance, shares at Dec. 31, 2015			13,835,128			(15,357)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net loss	$ (116,655)	$ (28,834)	$ (19,875)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion, and amortization	31,228	18,414	17,111
Impairment of proved and unproved oil and gas properties	138,086	19,359	12,298
Impairment of goodwill	1,547
Unrealized (gain) loss on derivative contracts	(125)	(3,614)	45
Dry hole costs			2,096
(Gain) loss on sales of oil and gas properties	(1,617)		121
Accretion of asset retirement obligations	550	317	217
Deferred income taxes	(26,533)	22,105
Amortization of deferred financing costs	264	164	103
Settlement of asset retirement obligations	(108)	(56)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	9,246	(5,305)	(12,141)
Decrease (increase) in prepaid expenses and other	779	(194)	(81)
(Decrease) increase in accounts payable and accrued expenses	(30,887)	28,408	2,171
(Decrease) increase in revenue and royalties payable	(8,739)	7,099	9,698
(Decrease) increase in advances	(5,929)	17,925	3,520
Net cash (used in) provided by operating activities	(10,440)	75,788	15,283
Cash flows from investing activities:
Acquisitions of oil and gas property	(8,706)	(18,772)	(86,687)
Additions to oil and gas property and equipment	(61,060)	(83,041)	(31,162)
Additions to other property and equipment	(378)	(1,385)	(678)
Reverse acquisition with Oak Valley, net of cash		(4,239)
Insurance proceeds			923
Proceeds from sales of oil and gas properties	3,441		488
Proceeds from sale of land	101
Net cash used in investing activities	(66,602)	(107,437)	(117,116)
Cash flows from financing activities:
Issuance of long-term debt		11,191
Reduction of long-term debt		(10,825)
Deferred financing costs	(141)	(613)	(425)
Contributions, net of issuance costs		106,920	107,530
Net cash (used in) provided by financing activities	(141)	106,673	107,105
Net (decrease) increase in cash and cash equivalents	(77,183)	75,024	5,272
Cash and cash equivalents at beginning of period	100,447	25,423	20,151
Cash and cash equivalents at end of period	23,264	100,447	25,423
Cash paid for:
Interest	415	493	375
Non-cash investing and financing activities:
Asset retirement obligations	150	237	1,033
Acquisitions of oil and gas properties	1,991
Stock issued for 2014 Eagle Ford Acquisition Properties		56,425
Proved And Unproved Property
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Impairment of proved and unproved oil and gas properties	$ 136,539	$ 19,359	$ 12,298

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2015
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 formed in 1969, is a growth-oriented independent oil and gas exploration and production company engaged in The Company also has conventional wells in East Texas, South Texas and Oklahoma. Unless the context otherwise requires, the terms “Earthstone” and the “Company” refer to Earthstone Energy, Inc. and it consolidated subsidiaries. Oak Valley Resources, LLC (“OVR”), is a Delaware limited liability company, formed on December 14, 2012. Prior to the Exchange (described below), OVR was an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (“NGLs”), with properties in Texas, Oklahoma, and Louisiana. OVR was formed through a series of transactions that conveyed properties and committed cash contributions from various investors including EnCap Investments L.P. (“EnCap”), Wells Fargo Central Pacific Holdings, Inc. (“Wells Fargo”), VILLCo Capital II, LLC (“VILLCo”) and an affiliate of OVR, Oak Valley Management, LLC (“OVM”). On December 19, 2014, the Company acquired three operating subsidiaries of OVR, in exchange for shares of Earthstone common stock (the “Exchange”), which resulted in a change of control of the Company. Pursuant to the Exchange Agreement, OVR contributed to Earthstone the membership interests of its three subsidiaries, Earthstone Operating, LLC (formerly Oak Valley Operating, LLC (“OVO”)), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”), in exchange for 9.124 million shares, representing 84% of the Company’s common stock. The transaction was accounted for as a reverse acquisition whereby Oak Valley was considered the acquirer for accounting purposes. All historical financial information, prior to December 19, 2014, contained in these Consolidated Financial Statements is that of Oak Valley. Immediately following the exchange, the Company, through its wholly owned subsidiary, Sabine, acquired an additional 20% undivided ownership interest in certain crude oil and natural gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of approximately 2.957 million shares of common stock (the “Contribution Agreement”) to Flatonia Energy, LLC, increasing the Company’s ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest. As a result of the share issuance to Flatonia, OVR’s ownership in the Company decreased from 84% to 66%.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 its wholly owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany accounts and transactions are eliminated in consolidation. As of December 31, 2015, the Company’s wholly-owned subsidiaries included: · Earthstone Operating, LLC (formerly Oak Valley Operating, LLC), a Texas limited liability company formed on May 26, 2011. Earthstone Operating serves as the operator on all Company-operated properties in Fayette and Gonzales Counties, Texas and Oklahoma; · EF Non-Op, LLC, a Texas limited liability company formed on December 1, 2010. EF Non-Op holds interests in oil and natural gas properties located in La Salle County, Texas; · Sabine River Energy, LLC, a Texas limited liability company formed on May 18, 2011. Sabine holds interests in oil and natural gas properties located in Texas and Oklahoma; · Basic Petroleum Services, Inc. (“BPS”), a Texas corporation formed March 30, 1977. BPS is a service company which provides services to one of the fields that the Company operates in South Texas; and · 1058286 B.C. Ltd (“Merger Sub”), a British Columbia corporation formed December 14, 2015. Merger Sub was incorporated for the purposes of effecting the previously announced arrangement agreement dated December 16, 2015 among the Company, Merger Sub and Lynden Energy Corp. and has not conducted any activities other than those incidental to its formation and the matters contemplated by the arrangement agreement. Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States (“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. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of our estimates. All the reserves data included in these Consolidated Financial Statements are 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 reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves 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 the carrying amounts of property, plant and equipment, goodwill and asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments, among others. 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. Further declines in commodity prices could result in an additional reduction in our fair value estimates and cause us to perform analyses to determine if our oil and natural gas properties need to be further impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates. See Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) Cash and Cash Equivalents Cash and cash equivalents consists of all demand deposits and funds invested in highly liquid investments with an original maturity date of three months or less. 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. At December 31, 2015 and 2014, the Company deemed all their significant account receivables collectible. Advances The Company, in its execution of its drilling program, has other working interest partners. The Company, through its joint operating agreements, requires its working interest partners to pay a drilling advance for their share of the estimated drilling and completion costs. Until such advances are applied to actual drilling and completion invoices, the Company carries the advance as a current liability on the consolidated balance sheets. The Company expects such advances to be applied against the partners’ joint interest billings for its share of drilling operations. 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 for hedge accounting. Accordingly, these derivative contracts are marked-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in Net gain (loss) on derivative contracts Net gain (loss) on derivative contracts Oil and Gas Properties Proved Properties The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, costs to acquire oil and 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. If additions to proved oil and gas properties will be paid within twelve months of year-end, then such additions are accrued at year-end and are included in Additions to oil and gas property and equipment The Company’s lease acquisition costs and development costs of proved oil and 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 gas producing property and related equipment was $30.7 million, $18.1 million, and $16.9 million, for the years ended December 31, 2015, 2014, and 2013, respectively. The Company reviews its proved oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. The Company recognized impairment charges on its proved oil and gas properties in 2015, 2014, and 2013. See Note 5 Asset Impairments. 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. If additions to unproved oil and gas properties will be paid within twelve months of year-end, then such additions are accrued for at year-end and are included in the Additions to oil and gas property and equipment 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 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 recognized impairment charges on its unproved oil and gas properties in 2015, 2014, and 2013. See Note 5 Asset Impairments. Goodwill We account for goodwill in accordance with Financial Accounting Standards Board (“FASB”), Accounting Standards Codification (ASC) 350, Intangibles—Goodwill and Other Note 5 Asset Impairments Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon, remediate oil and gas wells, remove equipment and facilities from leased acreage, and return land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or when an asset is installed at the producing location), and the costs of such liability increases the carrying amount of the related long-lived asset by the same amount. After the liability is initially recorded, the carrying amount of the related long-lived asset is increased over time through a charge to accretion expense each period and the capitalized cost is depleted on a units-of-production basis based on the proved developed reserves of the related assets. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability. See Note 10 Asset Retirement Obligations Business Combinations The Company accounts for the acquisition of oil and gas properties, that are not commonly controlled, based on the requirements of FASB ASC Topic 805, 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, 2015, 2014, or 2013. 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 gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2015, 2014 and 2013, one purchaser accounted for 62%, 60% and 21%, respectively, 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 2015, 2014, and 2013. The Company holds working interests in oil and 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. The Company recognizes the cash received as revenue. In 2015, one operator distributed 12% and in 2014, a different operator distributed 20% of the Company’s oil, natural gas and natural gas liquids revenues. In 2013, two operators distributed 47% and 11% 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 2015, 2014, and 2013. If purchasers and operators fail to perform pursuant to contractual terms, then the Company’s overall business may be adversely impacted. The Company’s management believes this risk is mitigated by the size, and reputation, of its purchasers and operators. Commodity derivative contracts held by the Company are with three counterparties. The counterparties have investment-grade ratings from Moody’s and Standard & Poor. 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. The Company’s management believes this risk is not significant based upon the size and reputation of the financial institutions. Income Taxes The provision for income taxes is based on taxes payable or refundable for the current year and deferred taxes on differences between the tax bases of assets and liabilities and their reported amounts in the consolidated financial statements, which result from temporary differences between the amount of taxable income and pretax financial income. The deferred tax assets and liabilities are calculated for the 2015 consolidated financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. Tax positions are evaluated for recognition and measurement, with deferred tax balances recorded at their anticipated settlement amounts. A valuation allowance has been provided for the 2015 deferred tax assets that based on current information is not expected to be realized. As noted in the Basis of Presentation, the historical financials, prior to December 19, 2014, are those of Oak Valley. Oak Valley was not subject to taxation and therefore tax provisions were not recorded on the historical consolidated financial statements. As result of the Exchange Agreement, Oak Valley as result of its change in tax status is now taxable and is subject to taxation and included in the purchase accounting adjustments is a charge to earnings to record a tax provision. The Company follows the provisions of FASB ASC Topic 740, Income Taxes Recently Issued Accounting Pronouncements Revenue Recognition – In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Consolidated Financial Statements. Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements. Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update is effective for interim and annual periods beginning after December 15, 2015. The Company will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods. The Company does not expect the adoption of this new presentation guidance to have a material impact on its Consolidated Balance Sheets. Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination. The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will adopt this standard update, as required, beginning with the first quarter of 2016, and does not expect it to have a material impact on its Consolidated Financial Statements. Income Taxes – In November 2015, the FASB issued updated guidance changing the presentation of deferred taxes on the balance sheet. The updated guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The standards update is effective for annual and interim periods beginning after December 15, 2016 with early adoption permitted. The Company elected to early-adopt this standards update as of December 31, 2015 with prospective application. See .

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Earthstone Energy Reverse Acquisition On December 19, 2014, the Company and OVR closed the Exchange. In this transaction, OVR contributed to the Company the membership interests of its three wholly-owned subsidiaries, which included producing assets, undeveloped acreage and cash. OVR received approximately 9.124 million shares of newly issued common stock, $0.001 par value per share (the “Common Stock”), of the Company. The Exchange resulted in a change of control of the Company. The Exchange has been accounted in accordance with FASB ASC An allocation of the purchase price was prepared using, among other things, the 2014 year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. (“CG&A”) that was adjusted and re-priced by the Company’s reserve engineering staff back to the December 19, 2014 acquisition date. The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets ( in thousands, except share and share price amounts Shares of Common Stock outstanding before the Exchange 1,734,988 Company director and officer restricted shares that vested in the Exchange 18,400 Shares of Common Stock issued in the Exchange 9,124,452 Total shares of Common Stock outstanding following the Exchange 10,877,840 Shares of Common Stock issued as consideration 1,753,388 Closing price of Common Stock (1) $ 19.08 Total purchase price $ 33,455 Estimated Fair Value of Liabilities Assumed: Current liabilities $ 7,631 Long-term debt 7,000 Deferred tax liability (2) 2,880 Asset retirement obligation 1,035 Amount attributable to liabilities assumed 18,546 Total purchase price plus liabilities assumed $ 52,001 Estimated Fair Value of Assets Acquired: Cash (3) $ 2,920 Other current assets 3,466 Proved oil and natural gas properties (4) (5) 21,813 Unproved oil and natural gas properties 5,524 Other non-current assets 745 Amount attributable to assets acquired $ 34,468 Goodwill (6) $ 17,533 (1) The share price used for the determination of the purchase price, was the adjusted closing price of the Common Stock on December 19, 2014. (2) This amount represents the recorded book value versus tax value difference in oil and natural gas properties and other net assets as of the date the Exchange on a tax effected basis of approximately 35%. The tax basis of the legacy Earthstone assets were not adjusted in the Exchange. As noted above, however, ASC 805 requires that the Company in a reverse acquisition record the legacy Earthstone net assets at fair value on the date of the Exchange; the fair value of the net assets was in excess of the tax basis and as such required the recognition of a deferred tax liability. (3) The components of cash flow in the Exchange transaction in which the legacy Earthstone assets were acquired was $7.1 million in notes payable and accrued interest that was paid in full in conjunction with the Exchange less the cash acquired of $2.9 million. (4) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $51.62 per barrel of oil and $4.58 per Mcf of natural gas after adjustments for transportation fees and regional price differentials. (5) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates 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. For additional information on Level 3 inputs, see Note 6 Fair Value Adjustments (6) Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. During the three months ended December 31, 2015, a decrease of $1.4 million was recorded to goodwill and reflect purchase price adjustments made to estimated items in the preliminary purchase price allocation. The goodwill recognized will not be deductible for tax purposes. 2014 Eagle Ford Acquisition Properties Also on December 19, 2014, immediately following the Exchange, Flatonia Energy, LLC (“Flatonia”), Parallel Resource Partners, LLC (“Parallel”), and Sabine, closed the transactions contemplated by the Contribution Agreement by and among the Company, OVR, Sabine, OVO, Parallel, and Flatonia, whereby Parallel contributed 28.57% of the oil and natural gas property interests held by Flatonia, a wholly owned subsidiary of Parallel, in consideration for approximately 2.957 million shares of Common Stock (the “Contribution”). The assets subject to the Contribution Agreement were oil and natural gas property interests in producing wells and acreage in the Eagle Ford trend of Texas (the “2014 Eagle Ford Acquisition Propertie s . An allocation of the purchase price was prepared using, the 2014 year-end reserve report prepared by CG&A that was adjusted and re-priced by the Company’s reserve engineering staff back to December 19, 2014. During the three months ended December 31, 2015, the preliminary purchase price allocation was adjusted due to the completion of the 2014 Flatonia tax return, with respect to the deferred tax liability. The following table summarizes the consideration paid to acquire the 2014 Eagle Ford Acquisition Properties and the estimated values of those net assets ( in thousands, except share and share price amounts Shares of Common Stock issued as consideration in the Contribution 2,957,288 Closing price of Common Stock (1) $ 19.08 Total purchase price $ 56,425 Estimated Fair Value of Liabilities Assumed: Deferred tax liability (2) $ 1,547 Asset retirement obligation 173 Amount attributable to liabilities assumed 1,720 Total purchase price plus liabilities assumed $ 58,145 Estimated Fair Value of Assets Acquired: Proved oil and natural gas properties (3) (4) $ 34,745 Unproved oil and natural gas properties 21,853 Amount attributable to assets acquired $ 56,598 Goodwill (5) $ 1,547 (1) The share price used for the determination of the purchase price, was the adjusted closing price of the Common Stock on December 19, 2014. (2) This amount represents the recorded book value to tax difference of the oil and natural gas properties as of the date of the closing of the Contribution Agreement on a tax effected basis of approximately 34%. As noted above, the Company received the net assets acquired at Flatonia’s carryover tax basis; however, ASC 805 requires assets acquired and liabilities assumed be measured at their fair values as of the acquisition date (3) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $56.36 per barrel of oil and $3.36 per Mcf of natural gas after adjustments for transportation fees and regional price differentials. (4) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates 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. For additional information on Level 3 inputs, see Note 6 Fair Value Adjustments (5) Goodwill was determined as the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. During the fourth quarter of 2015 and due to the current commodity price environment, the Company determined that the goodwill balance was not recoverable and therefore fully impaired it, recording a goodwill impairment charge Note 5 Asset Impairments The following unaudited pro forma combined condensed results of operations are provided for the years ended December 31, 2014 and 2013 as though the Exchange and Contribution had been completed as of January 1, 2013. 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. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Exchange or Contribution or any estimated costs that will be incurred to integrate the legacy Earthstone net assets and the 2014 Eagle Ford Acquisition Properties. 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, 2014 2013 (Unaudited) Revenue $ 85,633 $ 66,450 Income before taxes $ 16,196 $ 2,460 Net income available to Earthstone common stockholders $ 10,672 $ 1,610 Pro forma net loss per common share: Basic and diluted $ 0.77 $ 0.12 The Company’s historical financial information was adjusted to give effect to the pro formas events that were directly attributable to the Exchange and the Contribution and were factually supportable. The unaudited pro forma consolidated results include the historical revenues and expenses of the assets acquired and liabilities assumed in the transactions noted above with the following adjustments: · Adjustments to recognize incremental depletion expense under the successful efforts method of accounting based on the fair value of the oil and natural gas properties and incremental accretion expense based on the asset retirement costs of the oil and natural gas properties acquired; · Eliminate historical interest expense for the legacy Earthstone debt that was retired; · Eliminate transaction costs and non-recurring charges directly related to the transactions that were included in the historical results of operations for Earthstone and OVR in the amount of $3.3 million. Transaction costs directly related to the transactions that do not have a continuing impact on the combined Company’s operating results have been excluded from the 2014 and 2013 pro forma earnings; · Adjustments to recognize pro forma income tax based on an assumed approximate 35% rate; · Adjustments to convert the full cost method financial statement of Earthstone to successful efforts financial statements which included adjusting exploration expense which would not have been capitalized under successful efforts method of accounting for oil and natural gas activities; and · Adjustment to eliminate the non-recurring deferred tax expense charge for the conversion of the Oak Valley subsidiaries from a non-taxable partnership to a taxable corporation. 2013 Eagle Ford Acquisition In July 2013 and August 2013, the Company purchased producing wells and acreage in the Eagle Ford shale trend of South Texas for approximately $71.6 million and $15.1 million, respectively (the “2013 Eagle Ford Acquisition”). The 2013 Eagle Ford Acquisition was accounted for as a business combination in accordance with ASC Topic 805, which among other things, requires assets acquired and liabilities assumed to be measured at fair value as of the effective date of the acquisition. The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed: (In thousands) Purchase price $ 86,687 Allocation of purchase price: Proved properties (1) (2) $ 57,255 Unproved properties 30,041 Asset retirement obligations (609 ) Total $ 86,687 (1) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $99.32 per barrel of oil and $3.24 per Mcf of natural gas after adjustments for transportation fees and regional price differentials. (2) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates 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. For additional information on Level 3 inputs, see Note 6 Fair Value Adjustments . The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2013 as if the 2013 Eagle Ford Acquisition had been completed as of January 1, 2013. The pro forma combined results of operations for the year ended December 31, 2013 have been prepared by adjusting historical results of the Company to include the historical results of the 2013 Eagle Ford Acquisition. These 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. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Eagle Ford Acquisition or any estimated costs that will be incurred to integrate the 2013 Eagle Ford Acquisition. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors. The unaudited pro forma consolidated results include the Company’s historical financial information and the revenues and expenses of assets acquired and liabilities assumed in the 2013 Eagle Ford Acquisition ( in thousands except share amounts Year 2013 (Unaudited) Revenue $ 48,291 Loss before taxes $ (5,240 ) Net loss available to Earthstone common stockholders $ (3,406 ) Pro forma net loss per common share: Basic and diluted $ (0.37 ) The Company’s historical financial information was adjusted to give effect to the pro formas events that were directly attributable to 2013 Eagle Ford Property acquisition and were factually supportable. The unaudited pro forma consolidated results include the historical revenues and expenses of the assets acquired and liabilities assumed in the transactions noted above with the following adjustments: · Adjustments to recognize incremental depletion expense under the successful efforts method of accounting based on the fair value of the oil and natural gas properties and incremental accretion expense based on the asset retirement costs of the oil and natural gas properties acquired; · Eliminate transaction costs and non-recurring charges directly related to the transactions that were included in the historical results of operations for OVR in the amount of $1.1 million. Transaction costs directly related to the transactions that do not have a continuing impact on the Company’s operating results have been excluded from the 2013 pro forma earnings; and · Adjustments to recognize pro forma income tax based on an assumed approximately 35% rate. The amount of revenue and net income from the 2013 Eagle Ford Acquisition included in the Company’s Consolidated Statements of Operations for the year ended December 31, 2013, was $9.5 million and $6.2 million, respectively. Acquisition costs of $1.1 million, are included in General and administrative expense Other Acquisitions In June 2015, the Company acquired a 50% operated interest in two gross Austin Chalk wells, which hold approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production, with gross production as of the time of the acquisition of 44 barrels of oil equivalent per day (“BOEPD”) all of which was oil. Also during June 2015, the Company acquired additional acreage in northern Karnes County, Texas, increasing its total leasehold position to approximately 400 gross acres. The Company has a 33% working interest in the Karnes acreage. These two positions are adjacent to one another. The Company initiated drilling on the Karnes county acreage during the fourth quarter of 2015, with completions on four wells expected to occur during 2016. The Gonzales County acreage will provide for 13 gross Eagle Ford locations. The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands) Purchase price $ 4,066 Estimated fair value of assets acquired: Proved oil and natural gas properties $ 588 Unproved oil and natural gas properties 3,496 Total assets acquired $ 4,084 Estimated fair value of liabilities assumed: Asset retirement obligations $ 13 Other liabilities 5 Total liabilities assumed $ 18 Consideration paid $ 4,066 Pro forma financial information, assuming the acquisition occurred at the beginning of each period presented, has not been presented because the effect on the Company’s results for each of those periods is not material. The results of the above acquisitions have been included in the Company’s consolidated financial statements since the date of each acquisition. In June 2015, the Company acquired additional acreage and increased the Company’s working interest in wells in existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.0 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells. The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that are in the drilling and completion phase. In August 2015, the Company acquired a 33% working interest in approximately 1,650 gross acres, in Southern Gonzales County, Texas for $3.3 million. This acreage is anticipated to support 16 additional gross Eagle Ford locations. Divestitures In May 17, 2013, the Company sold undeveloped acreage and working interest in nine wells located in Guadalupe County, Texas, and Caldwell County, Texas for cash consideration of $0.5 million. The Company recorded a loss on sale of $0.1 million. The effective date of the sale was April 1, 2013. On March 28, 2013, the Company sold undeveloped acreage in Harrison County, Texas, and the working interest in one well for cash consideration of one hundred dollars. The Company recorded a loss on sale of $0.1 million. The effective date of the sale was April 1, 2013. In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes, Louisiana, for cash consideration of $3.4 million. The Company recorded a gain of $1.6 million on the sale. The effective date of the transaction was March 1, 2015.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Note 4. Derivative Financial Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815 Derivatives and Hedging It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The counterparties to the Company’s current derivative contracts are lenders in the Company’s Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Company’s Credit Agreement. The Company’s crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “ Net gain on derivative contracts With an individual derivative counterparty, the Company may have multiple hedge positions that expire at various points in the future and result in fair value asset and liability positions. At the end of each reporting period, those positions are offset to a single fair value asset or liability for each commodity, and the netted balance is reflected in the Consolidated Balance Sheets as an asset or a liability. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The Company had the following open crude oil and natural gas derivative contracts as of December 31, 2015: Period Instrument Commodity Volume in Bbls Fixed Price January 2016 - March 2016 Swap Crude Oil 15,000 $ 57.00 January 2016 - June 2016 Swap Crude Oil 60,000 $ 58.00 January 2016 - December 2016 Swap Crude Oil 60,000 $ 60.80 January 2016 - December 2016 Swap Crude Oil 60,000 $ 60.80 In January 2016 and March 2016, the Company entered into the following commodity derivative contracts: Period Instrument Commodity Volume in MMBtu/Bbls Fixed Price February 2016 - December 2016 Swap Natural Gas 770,000 $ 2.53 January 2017 - December 2017 Swap Natural Gas 480,000 $ 2.785 April 2016 - March 2017 Swap Crude Oil 120,000 $ 42.30 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, 2015 December 31, 2014 Derivatives not designated as hedging contracts under ASC Topic 815 Balance Sheet Location Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Commodity contracts Current derivative assets $ 3,694 $ — $ 3,694 $ 3,569 $ — $ 3,569 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, 2015 2014 2013 Derivatives not designated as hedging contracts under ASC Topic 815 Statement of Operations Location Unrealized gain (loss) on commodity contracts Net gain on derivative contracts $ 125 $ 3,614 $ (45 ) Realized gain on commodity contracts Net gain on derivative contracts $ 6,306 $ 778 $ 341 $ 6,431 $ 4,392 $ 296

Asset Impairments

Asset Impairments	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Asset Impairments	Note 5. Asset Impairments The Company had the following non-cash asset impairment charges for the years ended December 31, 2015, 2014 and 2013 ( in thousands Years Ended December 31, 2015 2014 2013 Proved property $ 93,984 $ 16,903 $ 9,817 Unproved property 42,555 2,456 2,481 Goodwill 1,547 — — Total $ 138,086 $ 19,359 $ 12,298

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 6. Fair Value Measurements FASB ASC Topic 820, Fair Value Measurements and Disclosure (“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, 2015. 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 Company’s model is validated by the counterparty’s marked-to-market statements. 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, 2015 Level 1 Level 2 Level 3 Total Financial assets Current derivative assets $ — $ 3,694 $ — $ 3,694 Total financial assets $ — $ 3,694 $ — $ 3,694 December 31, 2014 Financial assets Current derivative assets $ — $ 3,569 $ — $ 3,569 Total financial assets $ — $ 3,569 $ — $ 3,569 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. Property Impairments Oil and gas properties are measured at fair value on a nonrecurring basis. The impairment charge reduces the carrying values of oil and gas properties’ to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets. The Company recorded asset impairments of $ 94.0 million Goodwill Impairments The Company tests goodwill for impairment annually in the fourth quarter or whenever events or changes in circumstances indicate that the fair value of its reporting unit may have been reduced below its carrying value. For purposes of determining the goodwill impairment, the Company estimated the fair value of the goodwill using a variety of valuation methods, including the income and market approaches. The estimate of fair value requires the Company to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural gas production, commodity prices based on forward commodity price curves, operating and development costs and other factors. The Company recorded goodwill impairments of $1.5 million for the year ended December 31, 2015, related to its 2014 Eagle Ford Acquisition Properties. 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 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 Obligation 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 10 Asset Retirement Obligations

Equity

Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Equity	Note 7. Equity Earnings (Loss) Per Common Share Basic earnings per share is computed by dividing net income attributable to common shares by the basic weighted-average shares of common stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents. Common stock equivalents include awards issued under the Company’s long-term incentive plan discussed in Note 8 Stock Based Compensation The following table is a reconciliation of net income and weighted-average common shares outstanding for purposes of calculating basic and diluted loss per share. The number of shares for the year ended December 31, 2013, reflect the shares issued to OVR on December 19, 2014 as a result of the Exchange Agreement that was accounted for as a reverse acquisition. Years Ended December 31, (In thousands, except per share amounts) 2015 2014 2013 Net loss $ (116,655 ) $ (28,834 ) $ (19,875 ) Weighted average common shares outstanding: Basic 13,835 9,279 9,124 Diluted 13,835 9,279 9,124 Net loss per share: Basic $ (8.43 ) $ (3.11 ) $ (2.18 ) Diluted $ (8.43 ) $ (3.11 ) $ (2.18 ) Members’ Equity As was explained in Note 2 – Summary of Significant Account Policies – Principles of Consolidation Capital Call Notices In January 2013, OVR received cash investments in the amount of $16.8 million related to its first capital call notice sent to Wells Fargo, VILLCo, and OVM. In May 2013, OVR received cash investments in the amount of $23.7 million related to its second capital call notice to Investors. In June 2013, OVR received cash investments in the amount of $67.0 million related to its third capital call notice to Investors. In December 2014, OVR received cash investments in the amount of $107.0 million related to its third capital call notice to Investors. Common Stock On December 19, 2014, pursuant to the Exchange Agreement, the Company issued to OVR 9,124,452 shares (the “Exchange Shares”) of Earthstone common stock, in exchange for the outstanding membership interests of OVR’s three subsidiaries. The issuance of the Exchange Shares is exempt from registration as a private placement under Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), and Rule 506 promulgated thereunder, among other exemptions. Pursuant to the Contribution Agreement, OVR, through its wholly owned subsidiary, Sabine, acquired a 20% undivided ownership interest in certain oil and gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of 2,957,288 shares (the “Contribution Shares”) of Earthstone common stock to Flatonia Energy, LLC. The issuance of Contribution Shares is exempt from registration as a private placement under Section 4(a)(2) of the Securities Act, and Rule 506 promulgated thereunder, amount other exemption.

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock Based Compensation	Note 8. Stock Based Compensation 2014 Long-Term Incentive Plan In December 2014, stockholders approved and adopted the 2014 Long-Term Incentive Plan (the “2014 Plan”), which was effective upon the December 19, 2014 closing of the Exchange Agreement with OVR and shall remain in effect until the day prior to the tenth anniversary thereof. In October 2015, the 2014 Plan was amended to increase the number of shares of common stock authorized to be issued thereunder. Under the 2014 Plan, the Company may grant stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awards to directors, officers, employees and independent contractors of the Company and its subsidiaries or affiliates. The Company may also grant nonqualified stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors, subject to the conditions set forth in the 2014 Plan. Generally, all classes of Company employees are eligible to participate in the 2014 Plan. The 2014 Plan currently provides that a maximum of 1,500,000 shares of common stock may be issued in conjunction with awards granted under the 2014 Plan. Awards that are forfeited under the 2014 Plan will again be eligible for issuance as though the forfeited awards had never been issued. Similarly, awards settled in cash will not be counted against the shares authorized for issuance upon exercise of awards under the 2014 Plan. The 2014 Plan limits the aggregate number of shares of common stock that may be covered by stock options and/or stock appreciation rights granted to any eligible employee in any calendar year to 250,000 shares. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with awards (other than stock options or stock appreciation rights) granted to any eligible employee in any calendar year to 150,000 shares. The 2014 Plan also limits the maximum aggregate amount that may be paid in cash pursuant to awards (other than stock options or stock appreciation rights) made to any eligible employee in any calendar year to $2.0 million. At December 31, 2015, there were no shares issued and all 1,500,000 shares remained available for award.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Note 9. Long In December, 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility. The current borrowing base under the credit agreement is $80.0 million and is subject to redetermination during May and November of each year. As of December 31, 2015, outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is equal to a base rate (which is equal to the greater of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month LIBOR plus 1.00%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 1.75% for base rate loans and from 2.00% to 2.75% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee of 0.50% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. The Company is also required to pay customary letter of credit fees. Principal amounts outstanding under the credit facility are due and payable in full at maturity on December 19, 2018. All of the obligations under the credit agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. As of December 31, 2015, the Company had an $80.0 million borrowing base, with $11.2 million of debt outstanding, (bearing an interest rate of 2.351%), $0.3 million of letters of credit outstanding, resulting in $68.5 million of borrowing base availability under its credit facility. The credit facility contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period. As of December 31, 2015, the Company was in compliance with these covenants under the credit facility. Interest expense for 2015, 2014 and 2013 includes amortization of deferred financing costs of $0.3 million, $0.2 million, and $0.1 million, respectively. $0.8 million and $1.0 million, net of amortization, associated with the credit facility have been capitalized as of December 31, 2015 and 2014, respectively, and are amortized on a straight-line basis over the term of the credit agreement.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 10. Asset Retirement Obligations The Company has asset retirement obligations associated with the future plugging and abandonment of oil and gas properties and related facilities. The accretion of the asset retirement obligation is included in “ Lease operating expense The following table summarizes the Company’s asset retirement obligation transactions recorded during 2015 and 2014, and in accordance with the provisions of FASB ASC Topic 410 , Asset Retirement and Environmental Obligations (in thousands) 2015 2014 Beginning asset retirement obligations $ 6,078 $ 3,011 Acquisitions (1) — 2,742 Purchase price adjustment (2) (1,192 ) — Liabilities incurred 126 64 Accretion expense 550 317 Property dispositions (403 ) — Liabilities settled (108 ) (56 ) Revision of estimates 24 — Ending asset retirement obligations $ 5,075 $ 6,078 (1) See Note 3 Acquisitions and Divestitures (2) Note 3 Acquisition and Divestitures At December 31, 2014, $0.4 was classified as current. At December 31, 2015, the Company did not have any asset retirement obligations classified as current.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 11. Related Party Transactions FASB ASC Topic 850 , Related Party Disclosures ) The Company employs members of OVM. For the years ended December 31, 2015, 2014 and 2013, the Company made payments totaling $3.8 million, $3.9 million and $2.2 million, respectively, to these members as compensation for services and reimbursement of expenses. The payments are included in General and administrative expense The Company has business relationships with Certain Other Members of OVR and with companies that employ Certain Other Members of OVR. At December 31, 2015 and 2014, the Company had liabilities of $0.7 million and $2.3 million, respectively, owed to such members and companies. These amounts are included in Accounts payable

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 12. Commitments and Contingencies In the course of its business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state, and local environmental, health and safety laws and regulations and third party litigation. Commitments The following table summarizes the Company’s estimated future contractual commitments as of December 31, 2015 (in thousands) 2016 2017 2018 2019 2020 Thereafter Drilling contracts* $ 5,919 $ — $ — $ — $ — $ — Gas contract** 1,647 1,643 1,643 1,643 1,647 680 Office leases 724 738 661 627 — — Total $ 8,290 $ 2,381 $ 2,304 $ 2,270 $ 1,647 $ 680 * In January 2016, the Company suspended drilling and temporarily laid down the drilling rig. The above obligation reflects a negotiated lower daily drilling rate. Our rig contractor has agreed with the suspension, and the Company will not be required to immediately pay a full termination fee which would otherwise total approximately $5.7 million. Rather, the Company will pay approximately $600,000 per month, with such payments reducing the full termination fee. If industry conditions do not improve, then the Company may continue to further defer drilling operations. ** As a part of the 2013 Eagle Ford Acquisition as discussed in Note 3 Acquisitions and Divestitures , the Company ratified several long-term gas purchasing and gas processing contracts. As is customary in the industry, the Company has reserved gathering and processing capacity in a pipeline. In one of the contracts, the Company has a volume commitment, whereby the Company pays the owner of the pipeline a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity for the Company’s use. Since the time of the acquisition, the Company has not been able to meet its delivery commitments. The rate and terms under this purchasing and processing contract expire on June 1, 2021. The Company leases corporate office space in The Woodlands, Texas and Denver, Colorado. Rent expense was approximately $0.8 million, $0.4 million, and $0.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. As of December 31, 2015, minimum future lease commitments for subsequent annual periods for all non-cancelable operating leases was approximately $2.8 million. Contingencies Environmental The Company’s operations are subject to risks normally associated with the exploration for and the 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, the Company 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 the Company, filed suit in the 125 th EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP)

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Note 13. Income Taxes As a partnership, OVR was generally not subject to federal or state income tax on its taxable income. OVR’s taxable income and deductions were reported by the partners in their respective returns. Therefore, no income taxes were reported by OVR prior to the closing of the strategic merger on December 19, 2014. The following table shows the components of the Company’s income tax provision for the years ended December 31, 2015 and 2014 ( in thousands Years Ended December 31, 2015 2014 Current: Federal $ — $ — State 91 — Total current 91 — Deferred: Federal (26,214 ) 21,803 State (319 ) 302 Total deferred (26,533 ) 22,105 Total income tax (benefit) provision $ (26,442 ) $ 22,105 The following is a reconciliation of taxes computed at the corporate federal statutory income tax rate of 34% to the reported income tax rate provision for the years ended December 31, 2015 and 2014 ( in thousands, except percentages Years Ended December 31, 2015 2014 Net loss before income taxes $ (143,097 ) $ (6,729 ) Tax benefit computed at Federal statutory rate (48,653 ) (2,288 ) Non-taxable Oak Valley income prior to merger — (4,142 ) Deferred income tax arising from change in tax status of Oak Valley — 28,347 Non-deductible general and administrative expenses 534 — Return to accrual (1,398 ) — State income taxes, net of Federal benefit (743 ) 188 Valuation allowance 23,818 — Total income tax (benefit) expense $ (26,442 ) $ 22,105 Effective tax rate 18.5 % -328.5 % The Company’s effective tax rate for the year ended December 31, 2015, is approximately 18.5% which is 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 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 more likely-than-not assured, therefore the Company recorded a valuation allowance to reduce its overall net deferred tax asset portion to zero. 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. The deferred income tax provision for 2014 includes an initial charge of $28.3 million attributable to OVR becoming a taxable entity in December 2014, concurrent with the Reverse Acquisition. Significant components of the deferred tax assets and liabilities at December 31, 2015 and 2014 are as follows ( in thousands Years Ended December 31, 2015 2014 Deferred current income tax assets: Asset retirement obligation $ — $ 140 Deferred compensation — 81 Other — 5 Deferred current income tax assets — 226 Deferred noncurrent income tax assets (liabilities): Office and other equipment (253 ) (381 ) Oil & gas properties 23,177 (29,730 ) Asset retirement obligation 1,788 1,952 Intangible assets (7 ) 130 Unrealized derivative gain (1,284 ) (1,229 ) Federal net operating loss carryforward 339 — Other 59 — Net deferred noncurrent tax assets (liabilities) 23,819 (29,258 ) Valuation allowance (23,819 ) Net deferred tax asset (liability) $ — $ (29,032 ) As of December 31, 2015, the Company has an estimated U.S. net operating loss carryforward of $1.0 million, expiring in 2034 and 2035. 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 of the US Tax Code. The Company is still evaluating the impact, if any, of potential 382 limitations. Uncertain Tax Positions ASC 740, Income Taxes The Company files a consolidated federal 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, 2015, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities. On September 13, 2013, the United States Treasury Department and the Internal Revenue Service issued final tangible property regulations (the tangible property regulations) under provisions that include IRC Sections 162, 167 and 263(a). The tangible property regulations apply to amounts paid to acquire, produce or improve tangible property, as well as dispositions of such property. The general effective date of the tangible property regulations are for tax years beginning on or after January 1, 2014. Based on the Company's analysis management did not consider the impacts of the tangible property regulations to be material to the Company's consolidated financial position, its results of operations, or both.

Supplemental Selected Quarterly

Supplemental Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Supplemental Selected Quarterly Financial Data (Unaudited)	Note 14. Supplemental Selected Quarterly Financial Data (Unaudited) Three Months Ended, (In thousands, except per share data) March 31, 2015 June 30, 2015 September 30, 2015 December 31, 2015 Year Ended December 31, 2015 Oil and gas revenues $ 11,242 $ 14,958 $ 13,033 $ 8,231 Other revenues 78 1,775 47 26 Operating expenses 13,618 16,452 15,675 152,874 Operating (loss) income (2,298 ) 281 (2,595 ) (144,617 ) Other income (expense), net 599 (1,324 ) 5,124 1,733 Income tax benefit (expense) 585 295 (811 ) 26,373 Net (loss) income $ (1,114 ) $ (748 ) $ 1,718 $ (116,511 ) Basic and diluted net (loss) income per share $ (0.08 ) $ (0.05 ) $ 0.12 $ (8.42 ) Three Months Ended, (In thousands, except per share data) March 31, 2014 June 30, 2014 September 30, 2014 December 31, 2014 Year Ended December 31, 2014 Oil and gas revenues $ 11,577 $ 12,059 $ 11,957 $ 12,018 Other revenues 109 86 98 90 Operating expenses 7,777 9,191 10,204 31,407 Operating income (loss) 3,909 2,954 1,851 (19,299 ) Other (expense) income, net (1,169 ) (1,424 ) 2,363 4,086 Income tax expense — — — (22,105 ) Net income (loss) $ 2,740 $ 1,530 $ 4,214 $ (37,318 ) Basic and diluted net income (loss) per share $ 0.30 $ 0.17 $ 0.46 $ (3.83 )

Supplemental Information On Oil

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2015
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 The Company’s oil and gas activities for 2015, 2014 and 2013 were entirely within the United States of America. Costs incurred in oil and gas producing activities were as follows ( in thousands Years Ended December 31, 2015 2014 (1) 2013 Acquisition cost: Proved $ 4,508 $ 74,728 $ 51,488 Unproved 10,646 36,236 32,863 Exploration costs: Exploratory drilling — — 64 Geological and geophysical 142 111 394 Development costs 56,862 75,105 32,511 Total additions $ 72,158 $ 186,180 $ 117,320 (1) Acquisition costs include the fair value of the legacy Earthstone proved properties equal to $22.1 million and $5.5 million of unproved properties that were added in the Exchange Agreement which was accounted for as a reserve acquisition. Acquisitions costs also included $34.7 million and $21.9 million in proved and unproved additions related to the 2014 Eagle Ford Acquisition. During the years ended December 31, 2015, 2014 and 2013, additions to oil and gas properties of $0.2 million. $0.2 million and $1.0 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or acquired. The net changes in capitalized exploratory well costs were as follows ( in thousands December 31, 2015 2014 2013 Balance, beginning of year $ — $ — $ 2,032 Additions to capitalized exploratory well costs pending the determination of proved reserves — — 64 Capitalized exploratory well costs charged to expense — — (2,096 ) Balance, end of year $ — $ — $ — 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, 2015, 2014 and 2013 have been independently prepared by Cawley, Gillespie & Associates, Inc. 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, 2015, 2014, and 2013 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot prices which equates to $50.28 per barrel, $94.99 per barrel, and $96.94 per barrel, respectively. The natural gas prices as of December 31, 2015, 2014 and 2013 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.59 per MMBtu, $4.309 per MMBtu and $3.666 per MMBtu, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines. A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013 are as follows: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBOE) Balance - December 31, 2012 519 10,099 392 2,594 Extensions and discoveries 3,586 4,198 526 4,812 Sale of minerals in place (15 ) — — (15 ) Purchases of minerals in place 2,051 709 213 2,382 Production (163 ) (2,635 ) (134 ) (737 ) Revision to previous estimates 100 11,842 321 2,395 Balance - December 31, 2013 6,078 24,213 1,318 11,431 Extensions and discoveries 1,909 1,403 221 2,364 Purchases of minerals in place 7,025 6,064 437 8,473 Production (403 ) (2,132 ) (124 ) (882 ) Revision to previous estimates (806 ) 9,031 107 806 Balance - December 31, 2014 13,803 38,579 1,959 22,192 Extensions and discoveries 526 828 21 685 Sale 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 Proved developed reserves: December 31, 2012 296 8,245 268 1,938 December 31, 2013 1,307 11,053 557 3,706 December 31, 2014 6,093 16,214 1,005 9,800 December 31, 2015 6,114 10,954 673 8,613 Proved undeveloped reserves: December 31, 2012 5,782 15,968 1,050 9,493 December 31, 2013 4,771 13,160 761 7,725 December 31, 2014 7,710 22,365 954 12,392 December 31, 2015 3,247 2,384 317 3,961 Total proved reserves decreased by 9.6 MMBoe during 2015 which is comprised of 1.2 MMBoe in proved developed reserves and 8.4 MMBoe in proved undeveloped reserves. Due to successful drilling in its Eagle Ford and Bakken properties, the Company converted 1.7 MMBoe from proved undeveloped reserves to proved developed. Purchases of minerals in place added an additional 0.1 MMBoe to proved developed reserves. These additions were offset by sales of minerals in place of 1.4 MMBoe and production of 1.4 MMBoe The company also had downward revision of 0.2 MMBoe to proved developed reserves during the year ended December 31, 2015. At December 31, 2015 the Company’s estimated proved undeveloped reserves (PUDs) were 4.0 MMBoe, a 8.4 MMBoe net decrease over the previous year’s estimate of 12.4 MMBoe. The following details the changes in PUD reserves for 2015 ( in MBoe Beginning proved undeveloped reserves at December 31, 2014 12,392 Undeveloped reserves transfer to developed (1,700 ) Revision (9,340 ) Purchases 1,924 Extensions and discoveries 685 Ending proved undeveloped reserves at December 31, 2015 3,961 The change to the PUD reserves was a result of the significant decline in oil and natural gas prices from December 31, 2014 to December 31, 2015. Oil prices declined from $94.99 per barrel to $50.28 per barrel while natural gas prices decreased from $4.309 per MMBtu to $2.59 per MMBtu. Extensions and Discoveries during the year ended December 31, 2015 were from the Company’s operated Eagle Ford and non-operated Bakken properties. All of the Company’s purchases of minerals in place reserves during the year ended December 31, 2015, occurred in the Eagle Ford property in Gonzales County, Texas. Based on the Company’s year-end 2015 reserve report, the Company expects to drill all of its PUD locations within five years. The total proved reserves increase of 10.8 MMBoe during 2014 is comprised of 6.1 MMBoe in proved developed and 4.7 MMBoe in proved undeveloped reserves. During 2014, the Company added 2.4 MMBoe in proved reserves due to extension and discoveries, the majority of which is due to successful drilling in its operated Eagle Ford property in Fayette and Gonzales counties, Texas. Both new wells drilled and completed during 2014 along with the PUD locations that were added because of this successful drilling contributed to the increase in proved reserves. Purchase of minerals in place of 8.5 MMBoe were as a result of the Exchanges Agreement whereby Oak Valley acquired the legacy Earthstone assets through a reverse acquisition and the Contribution Agreement where the Company acquired additional interests in its operated Eagle Ford property. The total proved reserves increase of 8.8 MMBoe during 2013 is comprised of 1.8 MMBoe in proved developed and 7.0 MMBoe in proved undeveloped reserves. During 2013, the Company added 4.8 MMBoe in proved reserves due to successful drilling in both its operated and non-operated Eagle Ford properties. The non-operated Eagle Ford property is located in La Salle county, Texas. Purchases of minerals in place of 2.4 MMBoe were as a result of the purchase, during the second half of 2013, of an approximately 30% working interest of the Company’s operated Eagle Ford property. All of the Company’s increases through extensions and discoveries occurred in its operated Eagle Ford property in Fayette and Gonzales counties, Texas as a result of successful drilling during 2014 which added additional PUD locations as well. PUDs that were converted during the year occurred in both the Company’s operated Eagle Ford and non-operated Bakken properties and 62% of the conversions occurred in the Eagle Ford property. Extensions and Discoveries were from the Company’s operated Eagle Ford and non-operated Bakken properties. All of the Company’s purchases of PUD reserves occurred in the Eagle Ford property in Gonzales County, Texas. Based on the Company’s year-end 2015 reserve report, the Company expects to drill all of its PUD locations within five years. 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, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. PUD locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers. 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 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, 2015, 2014 and 2013, 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. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying 10% discount factor. The Standardized Measure is as follows ( in thousands December 31, 2015 2014 2013 Future cash inflows $ 481,131 $ 1,464,138 $ 718,049 Future production costs (192,349 ) (427,113 ) (202,957 ) Future development costs (91,725 ) (312,010 ) (220,828 ) Future income tax expense — (180,248 ) — Future net cash flows 197,057 544,767 294,264 10% annual discount for estimated timing of cash flows (92,661 ) (288,911 ) (168,907 ) Standardized measure of discounted future cash flows $ 104,396 $ 255,856 $ 125,357 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, 2015 ( in thousands December 31, 2015 2014 2013 Beginning of year $ 255,856 $ 125,357 $ 25,132 Sales of oil and gas produced, net of production costs (29,152 ) (35,794 ) (20,287 ) Sales of minerals in place (2,470 ) — (380 ) Net changes in prices and production costs (288,064 ) (34,681 ) 241 Extensions, discoveries, and improved recoveries 6,514 54,157 48,006 Changes in income taxes, net (1) 88,944 (88,944 ) — Previously estimated development costs incurred during the period 26,977 18,252 3,227 Net changes in future development costs 6,697 7,028 (22,966 ) Purchases of minerals in place 7,695 163,309 56,069 Revisions of previous quantity estimates (16,671 ) 16,283 26,259 Accretion of discount 25,586 12,536 2,513 Changes in timing of estimated cash flows and other 22,484 18,353 7,543 End of year $ 104,396 $ 255,856 $ 125,357 (1) As a result of the December 19, 2014 Exchange, all historical financial information contained in this report is that of OVR and its subsidiaries. OVR,

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts and balances of the Company and its wholly owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany accounts and transactions are eliminated in consolidation. As of December 31, 2015, the Company’s wholly-owned subsidiaries included: · Earthstone Operating, LLC (formerly Oak Valley Operating, LLC), a Texas limited liability company formed on May 26, 2011. Earthstone Operating serves as the operator on all Company-operated properties in Fayette and Gonzales Counties, Texas and Oklahoma; · EF Non-Op, LLC, a Texas limited liability company formed on December 1, 2010. EF Non-Op holds interests in oil and natural gas properties located in La Salle County, Texas; · Sabine River Energy, LLC, a Texas limited liability company formed on May 18, 2011. Sabine holds interests in oil and natural gas properties located in Texas and Oklahoma; · Basic Petroleum Services, Inc. (“BPS”), a Texas corporation formed March 30, 1977. BPS is a service company which provides services to one of the fields that the Company operates in South Texas; and · 1058286 B.C. Ltd (“Merger Sub”), a British Columbia corporation formed December 14, 2015. Merger Sub was incorporated for the purposes of effecting the previously announced arrangement agreement dated December 16, 2015 among the Company, Merger Sub and Lynden Energy Corp. and has not conducted any activities other than those incidental to its formation and the matters contemplated by the arrangement agreement.
Use of Estimates	Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States (“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. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of our estimates. All the reserves data included in these Consolidated Financial Statements are 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 reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves 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 the carrying amounts of property, plant and equipment, goodwill and asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments, among others. 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. Further declines in commodity prices could result in an additional reduction in our fair value estimates and cause us to perform analyses to determine if our oil and natural gas properties need to be further impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates. See Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consists of all demand deposits and funds invested in highly liquid investments with an original maturity date of three months or less.
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. At December 31, 2015 and 2014, the Company deemed all their significant account receivables collectible.
Advances	Advances The Company, in its execution of its drilling program, has other working interest partners. The Company, through its joint operating agreements, requires its working interest partners to pay a drilling advance for their share of the estimated drilling and completion costs. Until such advances are applied to actual drilling and completion invoices, the Company carries the advance as a current liability on the consolidated balance sheets. The Company expects such advances to be applied against the partners’ joint interest billings for its share of drilling operations.
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 for hedge accounting. Accordingly, these derivative contracts are marked-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in Net gain (loss) on derivative contracts Net gain (loss) on derivative contracts
Oil and Gas Properties	Oil and Gas Properties Proved Properties The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, costs to acquire oil and 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. If additions to proved oil and gas properties will be paid within twelve months of year-end, then such additions are accrued at year-end and are included in Additions to oil and gas property and equipment The Company’s lease acquisition costs and development costs of proved oil and 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 gas producing property and related equipment was $30.7 million, $18.1 million, and $16.9 million, for the years ended December 31, 2015, 2014, and 2013, respectively. The Company reviews its proved oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. The Company recognized impairment charges on its proved oil and gas properties in 2015, 2014, and 2013. See Note 5 Asset Impairments.
Unproved Properties	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. If additions to unproved oil and gas properties will be paid within twelve months of year-end, then such additions are accrued for at year-end and are included in the Additions to oil and gas property and equipment 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 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 recognized impairment charges on its unproved oil and gas properties in 2015, 2014, and 2013. See Note 5 Asset Impairments.
Goodwill	Goodwill We account for goodwill in accordance with Financial Accounting Standards Board (“FASB”), Accounting Standards Codification (ASC) 350, Intangibles—Goodwill and Other Note 5 Asset Impairments
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon, remediate oil and gas wells, remove equipment and facilities from leased acreage, and return land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or when an asset is installed at the producing location), and the costs of such liability increases the carrying amount of the related long-lived asset by the same amount. After the liability is initially recorded, the carrying amount of the related long-lived asset is increased over time through a charge to accretion expense each period and the capitalized cost is depleted on a units-of-production basis based on the proved developed reserves of the related assets. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability. See Note 10 Asset Retirement Obligations
Business Combinations	Business Combinations The Company accounts for the acquisition of oil and gas properties, that are not commonly controlled, based on the requirements of FASB ASC Topic 805, 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, 2015, 2014, or 2013.
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 gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2015, 2014 and 2013, one purchaser accounted for 62%, 60% and 21%, respectively, 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 2015, 2014, and 2013. The Company holds working interests in oil and 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. The Company recognizes the cash received as revenue. In 2015, one operator distributed 12% and in 2014, a different operator distributed 20% of the Company’s oil, natural gas and natural gas liquids revenues. In 2013, two operators distributed 47% and 11% 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 2015, 2014, and 2013. If purchasers and operators fail to perform pursuant to contractual terms, then the Company’s overall business may be adversely impacted. The Company’s management believes this risk is mitigated by the size, and reputation, of its purchasers and operators. Commodity derivative contracts held by the Company are with three counterparties. The counterparties have investment-grade ratings from Moody’s and Standard & Poor. 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. The Company’s management believes this risk is not significant based upon the size and reputation of the financial institutions.
Income Taxes	Income Taxes The provision for income taxes is based on taxes payable or refundable for the current year and deferred taxes on differences between the tax bases of assets and liabilities and their reported amounts in the consolidated financial statements, which result from temporary differences between the amount of taxable income and pretax financial income. The deferred tax assets and liabilities are calculated for the 2015 consolidated financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. Tax positions are evaluated for recognition and measurement, with deferred tax balances recorded at their anticipated settlement amounts. A valuation allowance has been provided for the 2015 deferred tax assets that based on current information is not expected to be realized. As noted in the Basis of Presentation, the historical financials, prior to December 19, 2014, are those of Oak Valley. Oak Valley was not subject to taxation and therefore tax provisions were not recorded on the historical consolidated financial statements. As result of the Exchange Agreement, Oak Valley as result of its change in tax status is now taxable and is subject to taxation and included in the purchase accounting adjustments is a charge to earnings to record a tax provision. The Company follows the provisions of FASB ASC Topic 740, Income Taxes
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements Revenue Recognition – In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Consolidated Financial Statements. Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements. Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update is effective for interim and annual periods beginning after December 15, 2015. The Company will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods. The Company does not expect the adoption of this new presentation guidance to have a material impact on its Consolidated Balance Sheets. Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination. The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will adopt this standard update, as required, beginning with the first quarter of 2016, and does not expect it to have a material impact on its Consolidated Financial Statements. Income Taxes – In November 2015, the FASB issued updated guidance changing the presentation of deferred taxes on the balance sheet. The updated guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The standards update is effective for annual and interim periods beginning after December 15, 2016 with early adoption permitted. The Company elected to early-adopt this standards update as of December 31, 2015 with prospective application. See .

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets	The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets ( in thousands, except share and share price amounts Shares of Common Stock outstanding before the Exchange 1,734,988 Company director and officer restricted shares that vested in the Exchange 18,400 Shares of Common Stock issued in the Exchange 9,124,452 Total shares of Common Stock outstanding following the Exchange 10,877,840 Shares of Common Stock issued as consideration 1,753,388 Closing price of Common Stock (1) $ 19.08 Total purchase price $ 33,455 Estimated Fair Value of Liabilities Assumed: Current liabilities $ 7,631 Long-term debt 7,000 Deferred tax liability (2) 2,880 Asset retirement obligation 1,035 Amount attributable to liabilities assumed 18,546 Total purchase price plus liabilities assumed $ 52,001 Estimated Fair Value of Assets Acquired: Cash (3) $ 2,920 Other current assets 3,466 Proved oil and natural gas properties (4) (5) 21,813 Unproved oil and natural gas properties 5,524 Other non-current assets 745 Amount attributable to assets acquired $ 34,468 Goodwill (6) $ 17,533 (1) The share price used for the determination of the purchase price, was the adjusted closing price of the Common Stock on December 19, 2014. (2) This amount represents the recorded book value versus tax value difference in oil and natural gas properties and other net assets as of the date the Exchange on a tax effected basis of approximately 35%. The tax basis of the legacy Earthstone assets were not adjusted in the Exchange. As noted above, however, ASC 805 requires that the Company in a reverse acquisition record the legacy Earthstone net assets at fair value on the date of the Exchange; the fair value of the net assets was in excess of the tax basis and as such required the recognition of a deferred tax liability. (3) The components of cash flow in the Exchange transaction in which the legacy Earthstone assets were acquired was $7.1 million in notes payable and accrued interest that was paid in full in conjunction with the Exchange less the cash acquired of $2.9 million. (4) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $51.62 per barrel of oil and $4.58 per Mcf of natural gas after adjustments for transportation fees and regional price differentials. (5) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates 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. For additional information on Level 3 inputs, see Note 6 Fair Value Adjustments (6) Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. During the three months ended December 31, 2015, a decrease of $1.4 million was recorded to goodwill and reflect purchase price adjustments made to estimated items in the preliminary purchase price allocation. The goodwill recognized will not be deductible for tax purposes.
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets	The following table summarizes the consideration paid to acquire the 2014 Eagle Ford Acquisition Properties and the estimated values of those net assets ( in thousands, except share and share price amounts Shares of Common Stock issued as consideration in the Contribution 2,957,288 Closing price of Common Stock (1) $ 19.08 Total purchase price $ 56,425 Estimated Fair Value of Liabilities Assumed: Deferred tax liability (2) $ 1,547 Asset retirement obligation 173 Amount attributable to liabilities assumed 1,720 Total purchase price plus liabilities assumed $ 58,145 Estimated Fair Value of Assets Acquired: Proved oil and natural gas properties (3) (4) $ 34,745 Unproved oil and natural gas properties 21,853 Amount attributable to assets acquired $ 56,598 Goodwill (5) $ 1,547 (1) The share price used for the determination of the purchase price, was the adjusted closing price of the Common Stock on December 19, 2014. (2) This amount represents the recorded book value to tax difference of the oil and natural gas properties as of the date of the closing of the Contribution Agreement on a tax effected basis of approximately 34%. As noted above, the Company received the net assets acquired at Flatonia’s carryover tax basis; however, ASC 805 requires assets acquired and liabilities assumed be measured at their fair values as of the acquisition date (3) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $56.36 per barrel of oil and $3.36 per Mcf of natural gas after adjustments for transportation fees and regional price differentials. (4) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates 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. For additional information on Level 3 inputs, see Note 6 Fair Value Adjustments (5) Goodwill was determined as the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. During the fourth quarter of 2015 and due to the current commodity price environment, the Company determined that the goodwill balance was not recoverable and therefore fully impaired it, recording a goodwill impairment charge Note 5 Asset Impairments
Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed	The following unaudited pro forma combined condensed results of operations are provided for the years ended December 31, 2014 and 2013 as though the Exchange and Contribution had been completed as of January 1, 2013. 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. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Exchange or Contribution or any estimated costs that will be incurred to integrate the legacy Earthstone net assets and the 2014 Eagle Ford Acquisition Properties. 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, 2014 2013 (Unaudited) Revenue $ 85,633 $ 66,450 Income before taxes $ 16,196 $ 2,460 Net income available to Earthstone common stockholders $ 10,672 $ 1,610 Pro forma net loss per common share: Basic and diluted $ 0.77 $ 0.12
2013 Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets	The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed: (In thousands) Purchase price $ 86,687 Allocation of purchase price: Proved properties (1) (2) $ 57,255 Unproved properties 30,041 Asset retirement obligations (609 ) Total $ 86,687 (1) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $99.32 per barrel of oil and $3.24 per Mcf of natural gas after adjustments for transportation fees and regional price differentials. (2) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates 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. For additional information on Level 3 inputs, see Note 6 Fair Value Adjustments .
Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed	The unaudited pro forma consolidated results include the Company’s historical financial information and the revenues and expenses of assets acquired and liabilities assumed in the 2013 Eagle Ford Acquisition ( in thousands except share amounts Year 2013 (Unaudited) Revenue $ 48,291 Loss before taxes $ (5,240 ) Net loss available to Earthstone common stockholders $ (3,406 ) Pro forma net loss per common share: Basic and diluted $ (0.37 )
Other Acquisitions [Member]
Business Acquisition [Line Items]
Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets	The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands) Purchase price $ 4,066 Estimated fair value of assets acquired: Proved oil and natural gas properties $ 588 Unproved oil and natural gas properties 3,496 Total assets acquired $ 4,084 Estimated fair value of liabilities assumed: Asset retirement obligations $ 13 Other liabilities 5 Total liabilities assumed $ 18 Consideration paid $ 4,066

Derivative Financial Instrume24

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Commodity Derivative Instruments	The Company had the following open crude oil and natural gas derivative contracts as of December 31, 2015: Period Instrument Commodity Volume in Bbls Fixed Price January 2016 - March 2016 Swap Crude Oil 15,000 $ 57.00 January 2016 - June 2016 Swap Crude Oil 60,000 $ 58.00 January 2016 - December 2016 Swap Crude Oil 60,000 $ 60.80 January 2016 - December 2016 Swap Crude Oil 60,000 $ 60.80 In January 2016 and March 2016, the Company entered into the following commodity derivative contracts: Period Instrument Commodity Volume in MMBtu/Bbls Fixed Price February 2016 - December 2016 Swap Natural Gas 770,000 $ 2.53 January 2017 - December 2017 Swap Natural Gas 480,000 $ 2.785 April 2016 - March 2017 Swap Crude Oil 120,000 $ 42.30
Summary of Gross and Net Information about Commodity 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, 2015 December 31, 2014 Derivatives not designated as hedging contracts under ASC Topic 815 Balance Sheet Location Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Commodity contracts Current derivative assets $ 3,694 $ — $ 3,694 $ 3,569 $ — $ 3,569
Realized and Unrealized Gains and Losses from Commodity 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, 2015 2014 2013 Derivatives not designated as hedging contracts under ASC Topic 815 Statement of Operations Location Unrealized gain (loss) on commodity contracts Net gain on derivative contracts $ 125 $ 3,614 $ (45 ) Realized gain on commodity contracts Net gain on derivative contracts $ 6,306 $ 778 $ 341 $ 6,431 $ 4,392 $ 296

Asset Impairments (Tables)

Asset Impairments (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Schedule of Non-Cash Asset Impairment Charges	The Company had the following non-cash asset impairment charges for the years ended December 31, 2015, 2014 and 2013 ( in thousands Years Ended December 31, 2015 2014 2013 Proved property $ 93,984 $ 16,903 $ 9,817 Unproved property 42,555 2,456 2,481 Goodwill 1,547 — — Total $ 138,086 $ 19,359 $ 12,298

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 Level 1 Level 2 Level 3 Total Financial assets Current derivative assets $ — $ 3,694 $ — $ 3,694 Total financial assets $ — $ 3,694 $ — $ 3,694 December 31, 2014 Financial assets Current derivative assets $ — $ 3,569 $ — $ 3,569 Total financial assets $ — $ 3,569 $ — $ 3,569

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Reconciliation of Net (Loss) Income and Weighted-Average Shares of Common Stock Outstanding for Calculating Basic and Diluted (Loss) Income Per Share	The following table is a reconciliation of net income and weighted-average common shares outstanding for purposes of calculating basic and diluted loss per share. The number of shares for the year ended December 31, 2013, reflect the shares issued to OVR on December 19, 2014 as a result of the Exchange Agreement that was accounted for as a reverse acquisition. Years Ended December 31, (In thousands, except per share amounts) 2015 2014 2013 Net loss $ (116,655 ) $ (28,834 ) $ (19,875 ) Weighted average common shares outstanding: Basic 13,835 9,279 9,124 Diluted 13,835 9,279 9,124 Net loss per share: Basic $ (8.43 ) $ (3.11 ) $ (2.18 ) Diluted $ (8.43 ) $ (3.11 ) $ (2.18 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Asset Retirement Obligation Transactions	The following table summarizes the Company’s asset retirement obligation transactions recorded during 2015 and 2014, and in accordance with the provisions of FASB ASC Topic 410 , Asset Retirement and Environmental Obligations (in thousands) 2015 2014 Beginning asset retirement obligations $ 6,078 $ 3,011 Acquisitions (1) — 2,742 Purchase price adjustment (2) (1,192 ) — Liabilities incurred 126 64 Accretion expense 550 317 Property dispositions (403 ) — Liabilities settled (108 ) (56 ) Revision of estimates 24 — Ending asset retirement obligations $ 5,075 $ 6,078 (1) See Note 3 Acquisitions and Divestitures (2) Note 3 Acquisition and Divestitures

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Future minimum payments	The following table summarizes the Company’s estimated future contractual commitments as of December 31, 2015 (in thousands) 2016 2017 2018 2019 2020 Thereafter Drilling contracts* $ 5,919 $ — $ — $ — $ — $ — Gas contract** 1,647 1,643 1,643 1,643 1,647 680 Office leases 724 738 661 627 — — Total $ 8,290 $ 2,381 $ 2,304 $ 2,270 $ 1,647 $ 680

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 ( in thousands Years Ended December 31, 2015 2014 Current: Federal $ — $ — State 91 — Total current 91 — Deferred: Federal (26,214 ) 21,803 State (319 ) 302 Total deferred (26,533 ) 22,105 Total income tax (benefit) provision $ (26,442 ) $ 22,105
Reconciliation of Taxes Computed at Corporate Federal Statutory Income Tax Rate	The following is a reconciliation of taxes computed at the corporate federal statutory income tax rate of 34% to the reported income tax rate provision for the years ended December 31, 2015 and 2014 ( in thousands, except percentages Years Ended December 31, 2015 2014 Net loss before income taxes $ (143,097 ) $ (6,729 ) Tax benefit computed at Federal statutory rate (48,653 ) (2,288 ) Non-taxable Oak Valley income prior to merger — (4,142 ) Deferred income tax arising from change in tax status of Oak Valley — 28,347 Non-deductible general and administrative expenses 534 — Return to accrual (1,398 ) — State income taxes, net of Federal benefit (743 ) 188 Valuation allowance 23,818 — Total income tax (benefit) expense $ (26,442 ) $ 22,105 Effective tax rate 18.5 % -328.5 %
Components of Deferred Tax Assets and Liabilities	Significant components of the deferred tax assets and liabilities at December 31, 2015 and 2014 are as follows ( in thousands Years Ended December 31, 2015 2014 Deferred current income tax assets: Asset retirement obligation $ — $ 140 Deferred compensation — 81 Other — 5 Deferred current income tax assets — 226 Deferred noncurrent income tax assets (liabilities): Office and other equipment (253 ) (381 ) Oil & gas properties 23,177 (29,730 ) Asset retirement obligation 1,788 1,952 Intangible assets (7 ) 130 Unrealized derivative gain (1,284 ) (1,229 ) Federal net operating loss carryforward 339 — Other 59 — Net deferred noncurrent tax assets (liabilities) 23,819 (29,258 ) Valuation allowance (23,819 ) Net deferred tax asset (liability) $ — $ (29,032 )

Supplemental Selected Quarter31

Supplemental Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Selected Quarterly Financial Data	Three Months Ended, (In thousands, except per share data) March 31, 2015 June 30, 2015 September 30, 2015 December 31, 2015 Year Ended December 31, 2015 Oil and gas revenues $ 11,242 $ 14,958 $ 13,033 $ 8,231 Other revenues 78 1,775 47 26 Operating expenses 13,618 16,452 15,675 152,874 Operating (loss) income (2,298 ) 281 (2,595 ) (144,617 ) Other income (expense), net 599 (1,324 ) 5,124 1,733 Income tax benefit (expense) 585 295 (811 ) 26,373 Net (loss) income $ (1,114 ) $ (748 ) $ 1,718 $ (116,511 ) Basic and diluted net (loss) income per share $ (0.08 ) $ (0.05 ) $ 0.12 $ (8.42 ) Three Months Ended, (In thousands, except per share data) March 31, 2014 June 30, 2014 September 30, 2014 December 31, 2014 Year Ended December 31, 2014 Oil and gas revenues $ 11,577 $ 12,059 $ 11,957 $ 12,018 Other revenues 109 86 98 90 Operating expenses 7,777 9,191 10,204 31,407 Operating income (loss) 3,909 2,954 1,851 (19,299 ) Other (expense) income, net (1,169 ) (1,424 ) 2,363 4,086 Income tax expense — — — (22,105 ) Net income (loss) $ 2,740 $ 1,530 $ 4,214 $ (37,318 ) Basic and diluted net income (loss) per share $ 0.30 $ 0.17 $ 0.46 $ (3.83 )

Supplemental Information On O32

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Costs Incurred in Oil and Gas Producing Activities	The Company’s oil and gas activities for 2015, 2014 and 2013 were entirely within the United States of America. Costs incurred in oil and gas producing activities were as follows ( in thousands Years Ended December 31, 2015 2014 (1) 2013 Acquisition cost: Proved $ 4,508 $ 74,728 $ 51,488 Unproved 10,646 36,236 32,863 Exploration costs: Exploratory drilling — — 64 Geological and geophysical 142 111 394 Development costs 56,862 75,105 32,511 Total additions $ 72,158 $ 186,180 $ 117,320 (1) Acquisition costs include the fair value of the legacy Earthstone proved properties equal to $22.1 million and $5.5 million of unproved properties that were added in the Exchange Agreement which was accounted for as a reserve acquisition. Acquisitions costs also included $34.7 million and $21.9 million in proved and unproved additions related to the 2014 Eagle Ford Acquisition.
Net Changes in Capitalized Exploratory Well Costs	The net changes in capitalized exploratory well costs were as follows ( in thousands December 31, 2015 2014 2013 Balance, beginning of year $ — $ — $ 2,032 Additions to capitalized exploratory well costs pending the determination of proved reserves — — 64 Capitalized exploratory well costs charged to expense — — (2,096 ) Balance, end of year $ — $ — $ —
Summary of Changes in Quantities of Proved Oil and natural Gas Reserves	A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013 are as follows: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBOE) Balance - December 31, 2012 519 10,099 392 2,594 Extensions and discoveries 3,586 4,198 526 4,812 Sale of minerals in place (15 ) — — (15 ) Purchases of minerals in place 2,051 709 213 2,382 Production (163 ) (2,635 ) (134 ) (737 ) Revision to previous estimates 100 11,842 321 2,395 Balance - December 31, 2013 6,078 24,213 1,318 11,431 Extensions and discoveries 1,909 1,403 221 2,364 Purchases of minerals in place 7,025 6,064 437 8,473 Production (403 ) (2,132 ) (124 ) (882 ) Revision to previous estimates (806 ) 9,031 107 806 Balance - December 31, 2014 13,803 38,579 1,959 22,192 Extensions and discoveries 526 828 21 685 Sale 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 Proved developed reserves: December 31, 2012 296 8,245 268 1,938 December 31, 2013 1,307 11,053 557 3,706 December 31, 2014 6,093 16,214 1,005 9,800 December 31, 2015 6,114 10,954 673 8,613 Proved undeveloped reserves: December 31, 2012 5,782 15,968 1,050 9,493 December 31, 2013 4,771 13,160 761 7,725 December 31, 2014 7,710 22,365 954 12,392 December 31, 2015 3,247 2,384 317 3,961
Changes in PUD reserves	Beginning proved undeveloped reserves at December 31, 2014 12,392 Undeveloped reserves transfer to developed (1,700 ) Revision (9,340 ) Purchases 1,924 Extensions and discoveries 685 Ending proved undeveloped reserves at December 31, 2015 3,961
Schedule Of Standardized Measure	The Standardized Measure is as follows ( in thousands December 31, 2015 2014 2013 Future cash inflows $ 481,131 $ 1,464,138 $ 718,049 Future production costs (192,349 ) (427,113 ) (202,957 ) Future development costs (91,725 ) (312,010 ) (220,828 ) Future income tax expense — (180,248 ) — Future net cash flows 197,057 544,767 294,264 10% annual discount for estimated timing of cash flows (92,661 ) (288,911 ) (168,907 ) Standardized measure of discounted future cash flows $ 104,396 $ 255,856 $ 125,357
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, 2015 ( in thousands December 31, 2015 2014 2013 Beginning of year $ 255,856 $ 125,357 $ 25,132 Sales of oil and gas produced, net of production costs (29,152 ) (35,794 ) (20,287 ) Sales of minerals in place (2,470 ) — (380 ) Net changes in prices and production costs (288,064 ) (34,681 ) 241 Extensions, discoveries, and improved recoveries 6,514 54,157 48,006 Changes in income taxes, net (1) 88,944 (88,944 ) — Previously estimated development costs incurred during the period 26,977 18,252 3,227 Net changes in future development costs 6,697 7,028 (22,966 ) Purchases of minerals in place 7,695 163,309 56,069 Revisions of previous quantity estimates (16,671 ) 16,283 26,259 Accretion of discount 25,586 12,536 2,513 Changes in timing of estimated cash flows and other 22,484 18,353 7,543 End of year $ 104,396 $ 255,856 $ 125,357 (1) As a result of the December 19, 2014 Exchange, all historical financial information contained in this report is that of OVR and its subsidiaries. OVR,

Organization and Basis of Pre33

Organization and Basis of Presentation - Additional Information (Details)	Dec. 19, 2014Subsidiaryshares	Dec. 31, 2015shares
Oak Valley Resources, LLC [Member]
Organization And Basis Of Presentation [Line Items]
Number of subsidiaries | Subsidiary	3
Common stock shares issued in exchange for acquisition	9,124,000
Percentage of common stock acquired	84.00%	66.00%
Flatonia Energy, LLC [Member]
Organization And Basis Of Presentation [Line Items]
Percentage of common stock acquired		20.00%
Additional ownership interest acquired in certain oil and gas properties		20.00%
Common stock shares issued in exchange for acquisition		2,957,000
Undivided ownership interest percentage before acquisition		30.00%
Undivided ownership interest percentage after acquisition		50.00%

Summary of Significant Accoun34

Summary of Significant Accounting Policies - Additional Information - (Details)	12 Months Ended
	Dec. 31, 2015USD ($)CustomerOperatorCounterparty	Dec. 31, 2014USD ($)CustomerOperator	Dec. 31, 2013USD ($)CustomerOperator
Summary Of Significant Accounting Policies [Line Items]
Number of major customer | Customer	1	1	1
Number of other customer accounted for 10% or more of revenues | Customer	0	0	0
Number of major operators | Operator	1		2
Number of other operators accounted for 10% or more of revenue | Operator	0	0	0
Derivative, number of counterparties | Counterparty	2
Liability for uncertain tax positions | $	$ 0	$ 0	$ 0
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Customer One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of revenues	62.00%	60.00%	21.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Operator One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of revenues	12.00%	20.00%	47.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Operator Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of revenues			11.00%
Proved Oil and Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Depletion expenses | $	$ 30,700,000	$ 18,100,000	$ 16,900,000
Unproved Oil and Gas Properties [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Unproved oil and gas lease term	3 years
Unproved Oil and Gas Properties [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Unproved oil and gas lease term	5 years

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details)

Dec. 19, 2014USD ($)$ / sharesshares

Aug. 31, 2013USD ($)

Jul. 31, 2013USD ($)

May. 17, 2013USD ($)Well

Mar. 28, 2013USD ($)Well

Aug. 31, 2015USD ($)aLocation

Jun. 30, 2015USD ($)aBoeWellLocation

Dec. 31, 2015USD ($)

Sep. 30, 2015USD ($)

Jun. 30, 2015USD ($)a

Mar. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Sep. 30, 2014USD ($)

Jun. 30, 2014USD ($)

Mar. 31, 2014USD ($)

Dec. 31, 2016Well

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Apr. 30, 2015USD ($)

Business Acquisition [Line Items]

General and administrative expense

$ 10,300,000

$ 7,864,000

$ 7,751,000

Goodwill

$ 17,532,000

$ 22,992,000

17,532,000

22,992,000

Revenues

49,390,000

47,994,000

29,943,000

Net loss

$ (116,511,000)

$ 1,718,000

$ (748,000)

$ (1,114,000)

$ (37,318,000)

$ 4,214,000

$ 1,530,000

$ 2,740,000

(116,655,000)

$ (28,834,000)

(19,875,000)

Company acquired gross acres | a

1,650

Working interest acquired

$ 3,300,000

Cash consideration

$ 3,400,000

Gain (loss) on sale of properties

$ 1,617,000

(121,000)

Effective date of transaction

Mar. 1, 2015

Guadalupe County, Texas, and Caldwell County, Texas [Member]

Business Acquisition [Line Items]

Cash consideration

$ 500,000

Gain (loss) on sale of properties

$ (100,000)

Number of oil wells sold | Well

9

Effective date of sale

Apr. 1, 2013

Harrison County, Texas [Member]

Business Acquisition [Line Items]

Cash consideration

$ 100

Gain (loss) on sale of properties

$ (100,000)

Number of oil wells sold | Well

1

Effective date of sale

Apr. 1, 2013

Earthstone Energy Reverse Acquisition [Member]

Business Acquisition [Line Items]

Common stock shares issued in exchange for acquisition | shares

9,124,000

Common stock, price per share | $ / shares

$ 0.001

Goodwill

$ 17,533,000

2014 Eagle Ford Properties [Member]

Business Acquisition [Line Items]

Percentage of oil and natural gas property interests held by a wholly owned subsidiary

28.57%

Common stock shares issued in exchange for acquisition | shares

2,957,288

Assumed income tax rate

35.00%

Goodwill

$ 1,547,000

Consideration paid

$ 56,425,000

2014 Eagle Ford Properties [Member] | Non-recurring Transaction Costs [Member]

Business Acquisition [Line Items]

General and administrative expense

$ 3,300,000

2013 Eagle Ford Acquisition [Member]

Business Acquisition [Line Items]

Assumed income tax rate

35.00%

Purchase price, total

$ 15,100,000

$ 71,600,000

Goodwill

$ 0

Effective date of acquisition

Jan. 1, 2013

Revenues

$ 9,500,000

Net loss

6,200,000

Acquisition cost

$ 1,100,000

Consideration paid

$ 86,687,000

2013 Eagle Ford Acquisition [Member] | Non-recurring Transaction Costs [Member]

Business Acquisition [Line Items]

General and administrative expense

$ 1,100,000

Other Acquisitions [Member]

Business Acquisition [Line Items]

Acquisition of working interest

33.00%

Number of locations for eagle ford with expected development | Location

16

Consideration paid

$ 4,066,000

Other Acquisitions [Member] | Austin Chalk Wells [Member]

Business Acquisition [Line Items]

Acquisition of operating interest

50.00%

Company acquired gross acres | a

1,000

1,000

Number of wells acquired | Well

2

Percentage of acres held for production

100.00%

Gross production, barrels of oil equivalents per day | Boe

44

Other Acquisitions [Member] | Northern Kames County [Member]

Business Acquisition [Line Items]

Acquisition of working interest

33.00%

Gross acres acquired | a

400

Other Acquisitions [Member] | Gonzales County Acreage [Member]

Business Acquisition [Line Items]

Number of locations for eagle ford with expected development | Location

13

Other Acquisitions [Member] | Banks Field of McKenzie County [Member]

Business Acquisition [Line Items]

Number of wells acquired | Well

41

Number of drilling wells acquired | Well

21

Consideration paid

$ 1,400,000

Purchase price adjustment for revenues, net for production taxes, operating expenses and capital costs

$ 2,000,000

Net acres acquired | a

164

Other Acquisitions [Member] | Scenario Forecast [Member] | Gonzales County Acreage [Member]

Business Acquisition [Line Items]

Number of drilling wells acquired | Well

4

Acquisitions and Divestitures36

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 19, 2014	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Total shares of Common Stock outstanding following the Exchange			13,835,128	13,835,128
Estimated Fair Value of Assets Acquired:
Goodwill			$ 17,532	$ 22,992
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Shares of Common Stock outstanding before the Exchange	1,734,988
Company director and officer restricted shares that vested in the Exchange	18,400
Shares of Common Stock issued in the Exchange	9,124,452
Total shares of Common Stock outstanding following the Exchange	10,877,840
Shares of Common Stock issued as consideration	1,753,388
Closing price of Common Stock	$ 19.08
Total purchase price	$ 33,455
Estimated Fair Value of Liabilities Assumed:
Current liabilities	7,631
Long-term debt	7,000
Deferred tax liability	2,880
Asset retirement obligation	1,035
Amount attributable to liabilities assumed	18,546
Total purchase price plus liabilities assumed	52,001
Estimated Fair Value of Assets Acquired:
Cash	2,920
Other current assets	3,466
Other non-current assets	745
Amount attributable to assets acquired	34,468
Goodwill	17,533
Earthstone Energy Reverse Acquisition [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	21,813
Earthstone Energy Reverse Acquisition [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	$ 5,524
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Shares of Common Stock issued as consideration in the Contribution	2,957,288
Closing price of Common Stock	$ 19.08
Estimated Fair Value of Liabilities Assumed:
Deferred tax liability	$ 1,547
Asset retirement obligation	173
Amount attributable to liabilities assumed	1,720
Total purchase price plus liabilities assumed	58,145
Estimated Fair Value of Assets Acquired:
Amount attributable to assets acquired	56,598
Goodwill	1,547
Consideration paid	56,425
2014 Eagle Ford Properties [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	34,745
2014 Eagle Ford Properties [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	$ 21,853
Other Acquisitions [Member]
Estimated Fair Value of Liabilities Assumed:
Asset retirement obligation		$ 13
Amount attributable to liabilities assumed		18
Other liabilities		5
Total purchase price plus liabilities assumed		4,066
Estimated Fair Value of Assets Acquired:
Amount attributable to assets acquired		4,084
Consideration paid		4,066
Other Acquisitions [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		588
Other Acquisitions [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		$ 3,496

Acquisitions and Divestitures37

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Parenthetical) (Details) $ in Thousands	Dec. 19, 2014USD ($)$ / bbl$ / Mcf	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Exchange tax rate			34.00%
Goodwill impairment charge			$ 1,547
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Exchange tax rate	35.00%
Business combination assets acquired notes payable and accrued interest	$ 7,100
Cash	$ 2,920
Weighted average commodity prices of oil | $ / bbl	51.62
Weighted average commodity prices of natural gas | $ / Mcf	4.58
Decrease in purchase price adjustments to goodwill		$ 1,400
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Exchange tax rate	34.00%
Weighted average commodity prices of oil | $ / bbl	56.36
Weighted average commodity prices of natural gas | $ / Mcf	3.36
Goodwill impairment charge		$ 1,500	$ 1,547

Acquisitions and Divestitures38

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, 2014	Dec. 31, 2013
Earthstone Energy Reverse Acquisition 2014 Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Revenue	$ 85,633	$ 66,450
Income (loss) before taxes	16,196	2,460
Net Income (loss) available to Earthstone common stockholders	$ 10,672	$ 1,610
Pro forma net loss per common share:
Basic and diluted	$ 0.77	$ 0.12
2013 Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Revenue		$ 48,291
Income (loss) before taxes		(5,240)
Net Income (loss) available to Earthstone common stockholders		$ (3,406)
Pro forma net loss per common share:
Basic and diluted		$ (0.37)

Acquisitions and Divestitures39

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire and Amounts of Assets Acquired and Liabilities Assumed (Details) - 2013 Eagle Ford Acquisition [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Total purchase price	$ 86,687
Allocation of purchase price:
Total purchase price plus liabilities assumed	86,687
Proved Oil and Gas Properties [Member]
Allocation of purchase price:
Properties	57,255
Unproved Oil and Gas Properties [Member]
Allocation of purchase price:
Properties	30,041
Asset Retirement Obligation Costs
Allocation of purchase price:
Asset retirement obligations	$ (609)

Acquisitions and Divestitures40

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire and Amounts of Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - 2013 Eagle Ford Acquisition [Member]	12 Months Ended
	Dec. 31, 2013$ / bbl$ / Mcf
Business Acquisition [Line Items]
Weighted average commodity prices of oil | $ / bbl	99.32
Weighted average commodity prices of natural gas | $ / Mcf	3.24

Derivative Financial Instrume41

Derivative Financial Instruments - Schedule of Open Crude Oil and Natural Gas Derivative Contracts (Details) - Swap [Member]	1 Months Ended		12 Months Ended
	Mar. 31, 2016MMBTU$ / bbl$ / MMBTUbbl	Jan. 31, 2016MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2015$ / bblbbl
February 2016 - December 2016 [Member] | Natural Gas [Member] | Scenario Forecast [Member]
Derivative [Line Items]
Volume in MMBtu | MMBTU	770,000
Fixed Price, MMBtu | $ / MMBTU	2.53
January 2017 - December 2017 [Member] | Natural Gas [Member] | Scenario Forecast [Member]
Derivative [Line Items]
Volume in MMBtu | MMBTU	480,000
Fixed Price, MMBtu | $ / MMBTU	2.785
Subsequent Event [Member] | February 2016 - December 2016 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume in MMBtu | MMBTU		770,000
Fixed Price, MMBtu | $ / MMBTU		2.53
Subsequent Event [Member] | January 2017 - December 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume in MMBtu | MMBTU		480,000
Fixed Price, MMBtu | $ / MMBTU		2.785
Crude Oil | April 2016 - March 2017 [Member] | Scenario Forecast [Member]
Derivative [Line Items]
Volume in Bbls | bbl	120,000
Fixed Price, Bbls | $ / bbl	42.30
Crude Oil | Subsequent Event [Member] | April 2016 - March 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl		120,000
Fixed Price, Bbls | $ / bbl		42.30
January 2016 - March 2016 [Member] | Crude Oil
Derivative [Line Items]
Volume in Bbls | bbl			15,000
Fixed Price, Bbls | $ / bbl			57
January 2016 - June 2016 [Member] | Crude Oil
Derivative [Line Items]
Volume in Bbls | bbl			60,000
Fixed Price, Bbls | $ / bbl			58
January 2016 - December 2016 [Member] | Crude Oil
Derivative [Line Items]
Volume in Bbls | bbl			60,000
Fixed Price, Bbls | $ / bbl			60.80
January 2016 - December 2016 [Member] | Crude Oil
Derivative [Line Items]
Volume in Bbls | bbl			60,000
Fixed Price, Bbls | $ / bbl			60.80

Derivative Financial Instrume42

Derivative Financial Instruments - Schedule of Location and Fair Value Amounts of All Derivative Instruments (Details) - Derivatives Not Designated as Hedging Contracts [Member] - Current Derivative Assets [Member] - Commodity Contracts [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Recognized Assets	$ 3,694	$ 3,569
Net Recognized Assets	$ 3,694	$ 3,569

Derivative Financial Instrume43

Derivative Financial Instruments - Summary of Gross and Net Information About Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments Gain Loss [Line Items]
Unrealized gain (loss) on commodity contracts	$ 125	$ 3,614	$ (45)
Net gain on derivative contracts	6,431	4,392	296
Derivatives Not Designated as Hedging Contracts [Member] | Net Gain On Derivative Contracts [Member]
Derivative Instruments Gain Loss [Line Items]
Unrealized gain (loss) on commodity contracts	125	3,614	(45)
Realized gain on commodity contracts	$ 6,306	$ 778	$ 341

Asset Impairments - Schedule of

Asset Impairments - Schedule of Non-Cash Asset Impairment Charges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Impairment Charges [Line Items]
Goodwill impairment charge	$ 1,547
Total	138,086	$ 19,359	$ 12,298
Proved Property [Member]
Asset Impairment Charges [Line Items]
Asset impairment charges	93,984	16,903	9,817
Unproved Property [Member]
Asset Impairment Charges [Line Items]
Asset impairment charges	$ 42,555	$ 2,456	$ 2,481

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value assets transfer from Level 1 to Level 2	$ 0	$ 0
Fair value assets transfer from Level 2 to Level 1	0	0
Fair value liabilities transfer from Level 1 to Level 2	0	0
Fair value liabilities transfer from Level 2 to Level 1	0	0
Impairment of goodwill		1,547,000
2014 Eagle Ford Properties [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of goodwill	$ 1,500,000	1,547,000
Proved Property [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments		93,984,000	$ 16,903,000	$ 9,817,000
Proved Property [Member] | Fair Value on a Nonrecurring Basis [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments		93,984,000	16,903,000	9,817,000
Unproved Property [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments		42,555,000	2,456,000	2,481,000
Unproved Property [Member] | Fair Value on a Nonrecurring Basis [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments		$ 42,555,000	$ 2,456,000	$ 2,481,000

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Financial assets
Current derivative assets	$ 3,694	$ 3,569
Fair Value on a Recurring Basis [Member]
Financial assets
Current derivative assets	3,694	3,569
Total financial assets	3,694	3,569
Fair Value on a Recurring Basis [Member] | Level 2 [Member]
Financial assets
Current derivative assets	3,694	3,569
Total financial assets	$ 3,694	$ 3,569

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ in Thousands	Dec. 19, 2014	Apr. 25, 2013	Dec. 21, 2012	Jun. 30, 2013	May. 31, 2013	Jan. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capital Unit [Line Items]
Outstanding common stock equivalents							0	0	0
Oak Valley Resources, LLC [Member]
Capital Unit [Line Items]
Cash investments received								$ 32,995
Percentage of common stock acquired	84.00%						66.00%
Oak Valley Resources, LLC [Member] | Common Stock [Member]
Capital Unit [Line Items]
Cash investments received								$ 2
Reverse acquisition, shares	9,124,452							1,753,388
Flatonia Energy, LLC [Member]
Capital Unit [Line Items]
Percentage of common stock acquired							20.00%
Flatonia Energy, LLC [Member] | Common Stock [Member]
Capital Unit [Line Items]
Reverse acquisition, shares							2,957,288
First Capital Call [Member]
Capital Unit [Line Items]
Cash investments received						$ 16,800
Second Capital Call [Member]
Capital Unit [Line Items]
Cash investments received					$ 23,700
Third Capital Call [Member]
Capital Unit [Line Items]
Cash investments received				$ 67,000				$ 107,000
ECC VI, LLC [Member]
Capital Unit [Line Items]
Ownership percentage			100.00%
Oak Valley Energy, LLC [Member]
Capital Unit [Line Items]
Ownership percentage			100.00%
EnCap Investments L.P. Wells Fargo Central Pacific Holdings, Inc, and Oak Valley Management, LLC
Capital Unit [Line Items]
Aggregate capital commitments			$ 150,000
Oak Valley Management Limited Liability Company
Capital Unit [Line Items]
Aggregate capital commitments									$ 1,700
Oak Valley Management Limited Liability Company | Private Placement [Member]
Capital Unit [Line Items]
Aggregate capital commitments		$ 62,800

Equity - Reconciliation of Net

Equity - Reconciliation of Net (Loss) Income and Weighted-Average Shares of Common Stock Outstanding for Calculating Basic and Diluted (Loss) Income Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Net loss	$ (116,511)	$ 1,718	$ (748)	$ (1,114)	$ (37,318)	$ 4,214	$ 1,530	$ 2,740	$ (116,655)	$ (28,834)	$ (19,875)
Weighted average common shares outstanding:
Basic									13,835,128	9,279,324	9,124,452
Diluted									13,835,128	9,279,324	9,124,452
Net loss per share:
Basic									$ (8.43)	$ (3.11)	$ (2.18)
Diluted									$ (8.43)	$ (3.11)	$ (2.18)

Stock Based Compensation - Addi

Stock Based Compensation - Additional Information (Details) - 2014 Long Term Incentive Plan [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Maximum number of shares available to issue		1,500,000
Maximum aggregate amount payable to pursue awards		$ 2
Number of shares issued during period	0
Number of shares remained available for grant	1,500,000
Stock Options or Stock Appreciation Rights [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares of common stock grants to eligible employee		250,000
Other Than Stock Options or Stock Appreciation Rights [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares of common stock grants to eligible employee		150,000

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt	$ 11,191,000	$ 11,191,000	$ 11,191,000
Amortization of deferred financing costs		264,000	164,000	$ 103,000
Deferred financing cost, net of amortization	1,000,000	800,000	1,000,000
Four Year Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000		500,000,000
Line of credit, maturity period	4 years
Current borrowing base under credit agreement	$ 80,000,000	$ 80,000,000	$ 80,000,000
Commitment fee percentage		0.50%
Debt outstanding maturity		Dec. 19, 2018
Long-term debt		$ 11,200,000
Long-term debt, percentage bearing interest rate		2.351%
Letters of credit outstanding amount		$ 300,000
Borrowing base available under credit facility		$ 68,500,000
Line of credit facility, covenant terms		The credit facility contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period.
Four Year Senior Secured Revolving Credit Facility [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage		0.50%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage		1.00%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage		2.00%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage		2.75%
Four Year Senior Secured Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage		1.00%
Four Year Senior Secured Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage		1.75%

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Asset Retirement Obligation Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Beginning asset retirement obligations	$ 6,078	$ 3,011
Acquisitions		2,742
Purchase price adjustment	(1,192)
Liabilities incurred	126	64
Accretion expense	550	317	$ 217
Property dispositions	(403)
Liabilities settled	(108)	(56)
Revision of estimates	24
Ending asset retirement obligations	$ 5,075	$ 6,078	$ 3,011

Asset Retirement Obligations 52

Asset Retirement Obligations - Additional Information (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	$ 0	$ 408,000

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oak Valley Management Limited Liability Company [Member]
Related Party Transaction [Line Items]
General and administrative expenses related to services	$ 3.8	$ 3.9	$ 2.2
Oak Valley Resources, Limited Liability Company [Member]
Related Party Transaction [Line Items]
Accounts payable, related parties	$ 0.7	$ 2.3

Commitment and Contingencies (D

Commitment and Contingencies (Details) $ in Thousands	Dec. 31, 2015USD ($)
Operating Leased Assets [Line Items]
2,016	$ 8,290
2,017	2,381
2,018	2,304
2,019	2,270
2,020	1,647
Thereafter	680
Drilling Contracts [Member]
Operating Leased Assets [Line Items]
2,016	5,919
Gas Contract [Member]
Operating Leased Assets [Line Items]
2,016	1,647
2,017	1,643
2,018	1,643
2,019	1,643
2,020	1,647
Thereafter	680
Office Leases [Member]
Operating Leased Assets [Line Items]
2,016	724
2,017	738
2,018	661
2,019	$ 627

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Jan. 31, 2016USD ($)	Dec. 31, 2015USD ($)MMBTU$ / MMBTU	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Loss Contingencies [Line Items]
Rent expense		$ 800,000	$ 400,000	$ 100,000
Minimum future lease commitments for non-cancelable leases		$ 2,800,000
Natural Gas Purchasing and Natural Gas Processing Contract [Member]
Loss Contingencies [Line Items]
Pipeline fee paid | $ / MMBTU		0.45
Holding pipeline capacity | MMBTU		10,000
Purchasing and processing contract expiry date		Jun. 1, 2021
Subsequent Event [Member] | Drilling Commitments
Loss Contingencies [Line Items]
Contract termination fee description	Our rig contractor has agreed with the suspension, and the Company will not be required to immediately pay a full terminate fee which would otherwise total approximately $5.7 million. Rather, the Company will pay approximately $600,000 per month, with such payments reducing the full terminate fee.
Termination fee	$ 5,700,000
Termination fee per month	$ 600,000

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Details) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Current:
State						$ 91
Total current						91
Deferred:
Federal						(26,214)	$ 21,803
State						(319)	302
Total deferred						(26,533)	22,105
Total income tax (benefit) provision	$ (26,373)	$ 811	$ (295)	$ (585)	$ 22,105	$ (26,442)	$ 22,105

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Statutory income tax rate	34.00%
Effective tax rate	18.50%	(328.50%)
Deferred income tax arising from change in tax status of Oak Valley		$ 28,347
Operating loss carryforward, net	$ 1,000
Net operating loss carryforwards expire beginning year	2,034
Net operating loss carryforwards expire ending year	2,035

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Taxes Computed at Corporate Federal Statutory Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Net loss before income taxes						$ (143,097)	$ (6,729)	$ (19,875)
Tax benefit computed at Federal statutory rate						(48,653)	(2,288)
Non-taxable Oak Valley income prior to merger							(4,142)
Deferred income tax arising from change in tax status of Oak Valley							28,347
Non-deductible general and administrative expenses						534
Return to accrual						(1,398)
State income taxes, net of Federal benefit						(743)	188
Valuation allowance						23,818
Total income tax (benefit) provision	$ (26,373)	$ 811	$ (295)	$ (585)	$ 22,105	$ (26,442)	$ 22,105
Effective tax rate						18.50%	(328.50%)

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred current income tax assets:
Asset retirement obligation		$ 140
Deferred compensation		81
Other		5
Deferred current income tax assets		226
Deferred noncurrent income tax assets (liabilities):
Office and other equipment	$ (253)	(381)
Oil & gas properties	23,177	(29,730)
Asset retirement obligation	1,788	1,952
Intangible assets (liabilities)	(7)	130
Unrealized derivative gain	(1,284)	(1,229)
Federal net operating loss carryforward	339
Other	59
Net deferred noncurrent tax assets (liabilities)	23,819	(29,258)
Valuation allowance	$ (23,819)
Net deferred tax asset (liability)		$ (29,032)

Supplemental Selected Quarter60

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, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Oil and gas revenues	$ 8,231	$ 13,033	$ 14,958	$ 11,242	$ 12,018	$ 11,957	$ 12,059	$ 11,577	$ 47,464	$ 47,611	$ 29,634
Other revenues	26	47	1,775	78	90	98	86	109
Operating expenses	152,874	15,675	16,452	13,618	31,407	10,204	9,191	7,777	198,619	58,580	49,643
Income (loss) from operations	(144,617)	(2,595)	281	(2,298)	(19,299)	1,851	2,954	3,909	(149,229)	(10,586)	(19,700)
Other income (expense), net	1,733	5,124	(1,324)	599	4,086	2,363	(1,424)	(1,169)	423	62	16
Income tax benefit (expense)	26,373	(811)	295	585	(22,105)				26,442	(22,105)
Net income (loss)	$ (116,511)	$ 1,718	$ (748)	$ (1,114)	$ (37,318)	$ 4,214	$ 1,530	$ 2,740	$ (116,655)	$ (28,834)	$ (19,875)
Basic and diluted net (loss) income per share	$ (8.42)	$ 0.12	$ (0.05)	$ (0.08)	$ (3.83)	$ 0.46	$ 0.17	$ 0.30

Supplemental Information On O61

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Acquisition cost:
Proved	$ 4,508	$ 74,728	$ 51,488
Unproved	10,646	36,236	32,863
Exploration costs:
Exploratory drilling			64
Geological and geophysical	142	111	394
Development costs	56,862	75,105	32,511
Total additions	$ 72,158	$ 186,180	$ 117,320

Supplemental Information On O62

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Costs Incurred Related to Oil and Gas Activities (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Proved	$ 4,508	$ 74,728	$ 51,488
Unproved	10,646	$ 36,236	$ 32,863
Oak Valley Resources L L C Exchange Agreement
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Proved	22,100
Unproved	5,500
2014 Eagle Ford
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Proved	34,700
Unproved	$ 21,900

Supplemental Information On O63

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MBoe$ / bbl$ / MMBTU	Dec. 31, 2014USD ($)MBoe$ / bbl$ / MMBTU	Dec. 31, 2013USD ($)MBoe$ / bbl$ / MMBTU	Dec. 31, 2012MBoe
Reserve Quantities [Line Items]
Additions to oil and gas properties | $	$ 72,158	$ 186,180	$ 117,320
Proved developed and undeveloped reserves increase (decrease)	(9,600)	10,800	8,800
Proved developed reserves decrease	1,200
Proved undeveloped reserves decrease	8,400
Conversion of proved undeveloped reserves to proved developed	1,700
Purchases of minerals in place	1,962	8,473	2,382
Sale of minerals in place	1,344		15
Production of minerals in place	1,437	882	737
Proved developed reserve downward revision	(9,484)	806	2,395
Proved undeveloped reserves	3,961	12,392	7,725	9,493
Estimated proved undeveloped reserves decrease	8,400
Proved developed reserves increase		6,100	1,800
Proved undeveloped reserves increase		4,700	7,000
Extensions and discoveries	685	2,364	4,812
Working interest percentage			30.00%
Oak Valley Resources L L C Exchange Agreement
Reserve Quantities [Line Items]
Extensions and discoveries		2,382
Eagle Ford Property
Reserve Quantities [Line Items]
Conversion of proved undeveloped reserves to proved developed	1,700
Purchases of minerals in place	100	8,500
Proved developed reserve downward revision	200
Proved undeveloped reserve converted percentage	62.00%
Henry Hub Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas | $ / MMBTU	2.59	4.309	3.666
Henry Hub Spot Price | Maximum [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas | $ / MMBTU	4.309
Henry Hub Spot Price | Minimum [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas | $ / MMBTU	2.59
West Texas Intermediate Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil | $ / bbl	50.28	94.99	96.94
West Texas Intermediate Spot Price | Maximum [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil | $ / bbl	94.99
West Texas Intermediate Spot Price | Minimum [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil | $ / bbl	50.28
New Wells
Reserve Quantities [Line Items]
Additions to oil and gas properties | $	$ 200	$ 200	$ 1,000

Supplemental Information On O64

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Net Changes in Capitalized Exploratory Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Balance, beginning of year	$ 0	$ 0	$ 2,032
Additions to capitalized exploratory well costs pending the determination of proved reserves			64
Capitalized exploratory well costs charged to expense			(2,096)
Balance, end of year	$ 0	$ 0	$ 0

Supplemental Information On O65

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, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf	Dec. 31, 2012MBoeMBblsMMcf
Reserve Quantities [Line Items]
Beginning balance | MBoe	22,192	11,431	2,594
Extensions and discoveries | MBoe	685	2,364	4,812
Sale of minerals in place | MBoe	(1,344)		(15)
Purchases of minerals in place | MBoe	1,962	8,473	2,382
Production | MBoe	(1,437)	(882)	(737)
Revision to previous estimates | MBoe	(9,484)	806	2,395
Ending Balance | MBoe	12,574	22,192	11,431
Proved developed reserves | MBoe	8,613	9,800	3,706	1,938
Proved undeveloped reserves | MBoe	3,961	12,392	7,725	9,493
Crude Oil [Member]
Reserve Quantities [Line Items]
Beginning balance	13,803	6,078	519
Extensions and discoveries	526	1,909	3,586
Sale of minerals in place	(4)		(15)
Purchases of minerals in place	1,641	7,025	2,051
Production	(904)	(403)	(163)
Revision to previous estimates	(5,701)	(806)	100
Ending balance	9,361	13,803	6,078
Proved developed reserves	6,114	6,093	1,307	296
Proved undeveloped reserves	3,247	7,710	4,771	5,782
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance | MMcf	38,579	24,213	10,099
Extensions and discoveries | MMcf	828	1,403	4,198
Sale of minerals in place | MMcf	(8,040)
Purchases of minerals in place | MMcf	679	6,064	709
Production | MMcf	(2,143)	(2,132)	(2,635)
Revision to previous estimates | MMcf	(16,565)	9,031	11,842
Ending Balance | MMcf	13,338	38,579	24,213
Proved developed reserves | MMcf	10,954	16,214	11,053	8,245
Proved undeveloped reserves | MMcf	2,384	22,365	13,160	15,968
Natural Gas Liquids
Reserve Quantities [Line Items]
Beginning balance	1,959	1,318	392
Extensions and discoveries	21	221	526
Purchases of minerals in place	208	437	213
Production	(176)	(124)	(134)
Revision to previous estimates	(1,022)	107	321
Ending balance	990	1,959	1,318
Proved developed reserves	673	1,005	557	268
Proved undeveloped reserves	317	954	761	1,050

Supplemental Information On O66

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule of Changes in Proved Undeveloped Reserves (Details)	12 Months Ended
	Dec. 31, 2015MBoe
Extractive Industries [Abstract]
Beginning Balance	12,392
Undeveloped reserves transfer to developed	(1,700)
Revision	(9,340)
Purchases	1,924
Extensions and discoveries	685
Ending balance	3,961

Supplemental Information On O67

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule Of Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Future cash inflows	$ 481,131	$ 1,464,138	$ 718,049
Future production costs	(192,349)	(427,113)	(202,957)
Future development costs	(91,725)	(312,010)	(220,828)
Future income tax expense		(180,248)
Future net cash flows	197,057	544,767	294,264
10% annual discount for estimated timing of cash flows	(92,661)	(288,911)	(168,907)
Standardized measure of discounted future cash flows	$ 104,396	$ 255,856	$ 125,357	$ 25,132

Supplemental Information On O68

Supplemental Information On Oil And Gas Exploration And Production Activities - Schedule Of 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, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Standardized Measure, beginning of year	$ 255,856	$ 125,357	$ 25,132
Sales of oil and gas produced, net of production costs	(29,152)	(35,794)	(20,287)
Sales of minerals in place	(2,470)		(380)
Net changes in prices and production costs	(288,064)	(34,681)	241
Extensions, discoveries, and improved recoveries	6,514	54,157	48,006
Changes in income taxes, net	88,944	(88,944)
Previously estimated development costs incurred during the period	26,977	18,252	3,227
Net changes in future development costs	6,697	7,028	(22,966)
Purchases of minerals in place	7,695	163,309	56,069
Revisions of previous quantity estimates	(16,671)	16,283	26,259
Accretion of discount	25,586	12,536	2,513
Changes in timing of estimated cash flows and other	22,484	18,353	7,543
Standardized Measure, end of year	$ 104,396	$ 255,856	$ 125,357