Earthstone Energy (ESTE) 10-K 27 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 25, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	ESTE
Entity Registrant Name	EARTHSTONE ENERGY INC
Entity Central Index Key	10254
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		13,835,128
Entity Public Float			$41,493,391

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$100,447	$25,423
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	14,016	8,122
Joint interest billings and other	9,417	7,541
Current derivative assets	3,569	154
Prepaid expenses and other current assets	1,578	122
Total current assets	129,027	41,362
Oil and gas properties, successful efforts method:
Proved properties	317,006	184,075
Unproved properties	76,791	43,011
Total oil and gas properties	393,797	227,086
Accumulated depreciation, depletion, and amortization	-97,920	-79,789
Net oil and gas properties	295,877	147,297
Other noncurrent assets:
Goodwill	22,992
Office and other equipment, less accumulated depreciation of $474 and $191, respectively	2,109	560
Land	101	101
Other noncurrent assets	1,282	538
TOTAL ASSETS	451,388	189,858
Current liabilities:
Accounts payable	28,753	7,428
Accrued expenses	20,529	5,768
Revenues and royalties payable	17,364	10,184
Advances	21,398	3,520
Current derivative liabilities		172
Asset retirement obligations	408	70
Total current liabilities	88,452	27,142
Noncurrent liabilities:
Noncurrent derivative liabilities		28
Long-term debt	11,191	10,825
Asset retirement obligations	5,670	2,941
Deferred tax liability	29,258
Other noncurrent liabilities	289
Total noncurrent liabilities	46,408	13,794
Total liabilities	134,860	40,936
Commitments and Contingencies (Note 11)
Equity:
Members' equity		148,922
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 2014 and none in 2013	14
Additional paid-in capital	358,086
Accumulated deficit	-41,112
Treasury stock, 15,414 shares in 2014 and none in 2013	-460
Total equity	316,528	148,922
TOTAL LIABILITIES AND EQUITY	$451,388	$189,858

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement Of Financial Position [Abstract]
Office and other equipment, accumulated depreciation	$474	$191
Preferred stock, par value	$0.00	$0.00
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	$0.00	$0.00
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	13,835,128	0
Common stock, shares outstanding	13,835,128	0
Treasury stock, shares	15,414	0

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil, natural gas, and natural gas liquids revenues:
Oil	$34,734	$16,038	$8,679
Natural gas	9,367	9,714	6,064
Natural gas liquids	3,510	3,882	2,348
Total oil, natural gas, and natural gas liquids revenues	47,611	29,634	17,091
Gathering income	383	430	419
(Loss) gain on sale of oil and gas properties		-121	4,785
Total revenues	47,994	29,943	22,295
Production costs:
Lease operating expense	10,122	8,426	6,211
Severance taxes	2,002	1,225	608
Re-engineering and workovers	708	342	570
Impairment expense	19,359	12,298	52,475
Depreciation, depletion, and amortization	18,414	17,111	12,191
Exploration expense	111	2,490	57
General and administrative expense	7,864	7,751	3,280
Total operating costs and expenses	58,580	49,643	75,392
Income (loss) from operations	-10,586	-19,700	-53,097
OTHER INCOME (EXPENSE)
Interest expense, net	-597	-487	-273
Net gain on derivative contracts	4,392	296
Other income, net	62	16	49
Total other income (expense)	3,857	-175	-224
Loss before income taxes	-6,729	-19,875	-53,321
Income tax expense	22,105
Net income (loss)	($28,834)	($19,875)	($53,321)
Net loss per common share:
Basic	($3.11)	($2.18)	($5.84)
Diluted	($3.11)	($2.18)	($5.84)
Weighted average common shares outstanding:
Basic	9,279,324	9,124,452	9,124,452
Diluted	9,279,324	9,124,452	9,124,452

Consolidated_Statements_of_Equ

Consolidated Statements of Equity (USD $)	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]	Oak Valley Resources, LLC [Member]	Oak Valley Resources, LLC [Member]	Oak Valley Resources, LLC [Member]	Oak Valley Resources, LLC [Member]	Oak Valley Resources, LLC [Member]	Oak Valley Resources, LLC [Member]	Eagle Ford [Member]	Eagle Ford [Member]	Eagle Ford [Member]
In Thousands, except Share data								Members' Equity [Member]	Members' Equity [Member]	Common Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]		Common Stock [Member]	Additional Paid-in Capital [Member]
									Subsidiaries [Member]		Subsidiaries [Member]		Subsidiaries [Member]
Beginning Balance, amount at Dec. 31, 2011	$90,985	$90,985
Contributions							24,790	24,790
Distributions	-1,187	-1,187
Net income (loss)	-53,321	-53,321
Ending 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				-15,414		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			-15,414

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net loss	($28,834)	($19,875)	($53,321)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	18,414	17,111	12,191
Impairment of proved and unproved oil and gas properties	19,359	12,298	52,475
Unrealized (gain) loss on derivative contracts	-3,614	45
Dry hole costs		2,096	57
Loss (gain) on sales of oil and gas properties		121	-4,785
Accretion of asset retirement obligations	317	217	179
Deferred income taxes	22,105
Amortization of deferred financing costs	164	103	48
Settlement of asset retirement obligations	-56
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	-5,305	-12,141	1,202
(Increase) decrease in prepaid expenses and other	-194	-81	89
Increase in accounts payable and accrued expenses	28,408	2,171	6,762
Increase in revenue and royalties payable	7,099	9,698	88
Increase in advances	17,925	3,520
Net cash provided by operating activities	75,788	15,283	14,985
Cash flows from investing activities:
Acquisitions of proved and unproved property	-18,772	-86,687
Additions to oil and gas property and equipment	-83,041	-31,162	-39,433
Additions to other property and equipment	-1,385	-678	-97
Reverse acquisition with Oak Valley, net of cash	-4,239
Insurance proceeds		923
Proceeds from sales of oil and gas properties		488	9,976
Net cash used in investing activities	-107,437	-117,116	-29,554
Cash flows from financing activities:
Issuance of long-term debt	11,191		10,825
Reduction of long-term debt	-10,825		-5,192
Deferred financing costs	-613	-425	-20
Contributions, net of issuance costs	106,920	107,530	24,790
Distributions			-1,187
Net cash provided by financing activities	106,673	107,105	29,216
Net increase in cash and cash equivalents	75,024	5,272	14,647
Cash and cash equivalents at beginning of period	25,423	20,151	5,504
Cash and cash equivalents at end of period	100,447	25,423	20,151
Cash paid for:
Interest	493	375	238
Non-cash investing and financing activities:
Asset retirement obligations	237	1,033	66
Stock issued for 2014 Eagle Ford Acquisition Properties	$56,425

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2014
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 acquisition, development, exploration and production of onshore, unconventional reserves, with a current focus on the Eagle Ford trend of South Texas and in the Williston Basin of North Dakota and Montana. The Company also has conventional wells in East Texas, South Texas, Louisiana and Oklahoma.  Unless the context otherwise requires, the terms “Earthstone” and the “Company” refer to Earthstone Energy, Inc. and it consolidated subsidiaries.  The Company has evaluated events or transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements.
	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 (“NGL”), 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, 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 has been accounted for as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes.  All historical financial information contained in this Annual Report on Form 10-K is that of Oak Valley.
	Immediately following the exchange, the Company, through its now wholly owned subsidiary, Sabine, acquired an additional 20% undivided ownership interest in certain crude oil and 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_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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. Prior to being capitalized on December 21, 2012, all of the Company’s wholly owned subsidiaries were controlled by EnCap. All of the companies included in the transaction had fiscal years ending December 31. The consolidated financial statements for the period ended December 31, 2012 were prepared by combining all the previously separate subsidiaries in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC Topic 805”). ASC Topic 805 states that if a transaction combines two or more commonly controlled entities that historically have not been presented together, the resulting financial statements for those periods presented require retrospective presentation of the financial statements for all the periods presented, as if the combination had been in effect since the inception of common control.
	When accounting for a transfer of assets or exchange of equity interests between entities under common control, the entity that receives the net assets or the equity interests should initially measure the assets and liabilities transferred at their historical carrying amounts. Therefore, the net assets included in the accompanying consolidated financial statements are shown at their historical carrying value.
	On December 18, 2012, prior to the assignment of membership interests of Oak Valley Energy, LLC, a Delaware Limited Liability Company (“OVE”), to the Company, one of OVE’s subsidiaries was transferred to a non-affiliated entity. In accordance with ASC Topic 805, the consolidated financial statements include the activities of that subsidiary through the date of transfer. The amount of revenue and net income from the OVE subsidiary included in the Company’s Consolidated Statement of Operations for the year ended December 31, 2012, was $4.2 million and $2.4 million, respectively. Please see Note 3 “Acquisitions and Divestitures” for more information on this transfer.
	As of December 31, 2014, the Company’s wholly-owned subsidiaries included:
	·	Oak Valley Operating, LLC, a Texas limited liability company formed on May 26, 2011. OVO serves as the operator on all Company-operated properties in Fayette and Gonzales Counties, Texas, Louisiana 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, Louisiana 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.
	All intercompany accounts and transactions are eliminated in consolidation.
	Use of Estimates
	The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States 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. Estimates and assumptions that, in the opinion of the Company’s management, are significant include oil and natural gas reserves and the related cash flow estimates used in depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, fair value estimates, asset retirement obligations, oil and natural gas revenue accruals, lease operating expense accruals, and capital accruals. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.
	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 NGL purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and NGL 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, 2014, 2013, and 2012, the Company did not have an allowance for doubtful accounts as all accounts receivable were deemed collectible by management.
	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 its balance sheet. 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” in the Consolidated Statement of Operations as unrealized gains or losses on derivative contracts.  Realized gains or losses on derivative contracts are also recognized in “Net gain (loss) on derivative contracts” in the Consolidated Statements of Operations.
	Proved Oil and Gas Properties
	The Company follows the successful efforts method of accounting for its oil and gas properties. Costs incurred by the Company related to the acquisition of oil and gas properties and the cost of drilling development wells and successful exploratory wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale of oil and gas properties, the costs and related accumulated depreciation, depletion, and amortization are eliminated from the accounts and the resulting gain or loss is recognized.
	Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. 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” financial statement line item on the Consolidated Statements of Cash Flows. Gains and losses arising from the sale of properties are included in operating income (loss) on the Consolidated Statement of Operations.
	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 $18.1 million, $16.9 million, and $12.2 million, for the years ended December 31, 2014, 2013, and 2012, respectively.
	Proved oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the expected future cash flow expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, then the carrying value is written down to its estimated fair value.
	Each component of an impairment calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, estimated future net cash flows, and fair value. The Company recognized impairments of $16.9 million, $9.8 million, and $43.9 million for the years ended December 31, 2014, 2013, and 2012, respectively, on proved oil and gas properties.
	Unproved Oil and Gas 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” financial statement line item on the Consolidated Statements of Cash Flows. Unproved oil and gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.
	Unproved properties are assessed periodically to determine whether they have been impaired based on remaining lease term, drilling results, reservoir performance, seismic interpretation, or future plans to develop acreage.
	The Company recognized impairments of $2.5 million, $2.5 million, and $8.6 million for the years ended December 31, 2014, 2013, and 2012, respectively, on unproved oil and gas properties.
	Goodwill
	We account for goodwill in accordance with ASC 350, Intangibles—Goodwill and Other (ASC 350). Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. The company carried goodwill as of December 31, 2014 related to the reverse acquisition with Earthstone and the 2014 Eagle Ford Acquisition.  See Note 3 “Acquisitions and Divestitures” for further discussion regarding the goodwill associated with the transactions.
	Accounting Standards Update (ASU) No. 2011-08, Testing for Goodwill Impairment (ASU 2011-08), simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying value. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test. However, if the same conclusion is not reached, the entity is required to perform the first step of the two-step impairment test. In this step, the fair value of the reporting unit is calculated and compared to the carrying value of the reporting unit. If the carrying value exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of impairment loss, if any. ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test.
	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 9 “Asset Retirement Obligations” for further disclosure regarding the asset retirement obligation.
	Business Combinations
	The Company accounts for the acquisition of oil and gas properties, that are not commonly controlled, based on the requirements of ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved oil and gas property as business combinations.
	Revenue Recognition
	Oil, natural gas, and NGL revenues represent income from production and delivery of oil, natural gas, and NGL, 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, 2014, 2013, or 2012.
	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 NGL 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 2014 and 2013, one purchaser accounted for 60% and 21%, of the Company’s oil, natural gas, and NGL revenues, respectively. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and NGL revenues during 2014, 2013, and 2012.
	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 NGL to the purchaser, collects the cash, and distributes the cash to the Company. The Company recognizes the cash received as revenue. In 2014, one operator distributed 20% of the Company’s oil, natural gas and NGL revenues.  In 2013, two operators distributed 47% and 11% of the Company’s oil, natural gas, and NGL revenues. In 2012, two operators distributed 65% and 18% of the Company’s oil, natural gas, and NGL revenues. No other operator accounted for 10% or more of the Company’s oil, natural gas, and NGL revenues during 2013, 2012, and 2011.
	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 two counterparties. Both counterparties are participants in the Company’s credit facility and possess 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 bank 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. Deferred tax assets and liabilities are included in the 2014 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 is provided for deferred tax assets not expected to be realized.  As noted in the Principles of Consolidation the historical financials are those of OVR. OVR is 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 (“ASC Topic 740”), relating to accounting for uncertainties in income taxes. ASC Topic 740 clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. ASC Topic 740 requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. ASC Topic 740 also provides guidance on measurement, classification, interest and penalties and disclosure. Tax positions taken related to the Company’s pass-through status and state income tax liability, including deductibility of expenses, have been reviewed and the Company’s management is of the opinion that material positions taken by the Company would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2014, 2013, or 2012. The 2011 through 2014 tax years generally remain subject to examination.
	Recently Issued Accounting Pronouncements
	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 around contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. The standards update is effective for interim and annual periods beginning after December 15, 2016. We will adopt this standards update, as required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact, if any, of this guidance on its consolidated financial statements.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions Disclosures	Note 3. Acquisitions and Divestitures
	Earthstone Energy Reverse Acquisition
	On December 19, 2014, the Company and OVR closed the transactions contemplated by the Exchange Agreement  dated May 15, 2014 and as amended September 26, 2014 between the Company and OVR whereby OVR contributed to the Company the membership interests of its three wholly-owned subsidiaries, which included producing assets, undeveloped acreage and substantially all of its cash of approximately $130 million, inclusive of approximately $107 million in cash received from members’ capital commitments received immediately prior to the Exchange. OVR received approximately 9.1 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 805, Business Combinations (“ASC 805”) as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes and Earthstone is the acquiree. ASC 805 also requires, that among other things, assets acquired and liabilities assumed to be measured at their acquisition date fair values. The results of operations from Earthstone’s legacy assets are reflected in the Company’s consolidated statement of operations beginning December 19, 2014.
	An allocation of the purchase price was prepared using, among other things, the year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to December 19, 2014. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Earthstone Energy, Inc. tax return and certain accruals and includes the use of estimates based on information that was available to management at the time these audited consolidated financial statements were prepared. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.
	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		$	7,852
	Long-term debt			7,000
	Deferred tax liability (2)			2,880
	Asset retirement obligation			2,227
	Amount attributable to liabilities assumed			19,959
	Total purchase price plus liabilities assumed		$	53,414
	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)		$	18,946
	-1	The share prices 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 5 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. 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 a wholly owned subsidiary of the Company, Sabine, closed the transactions contemplated by the Contribution Agreement dated October 16, 2014 (the “Contribution Agreement”), by and among the Company, OVR, Sabine, Oak Valley Operating, LLC, Parallel, and Flatonia,  whereby Parallel contributed 28.57% of the oil and gas property interests held by Flatonia, a wholly owned subsidiary of Parallel, in consideration for approximately 2.96 million shares of Common Stock (the “Contribution”). The assets subject to the Contribution Agreement were certain oil and gas property interests in producing wells and acreage in the Eagle Ford trend of Texas (the “2014 Eagle Ford Acquisition Properties”). One of the subsidiaries included in the Exchange is the operator of the 2014 Eagle Ford Acquisition Properties. The only relationship that Flatonia or Parallel had with this subsidiary or the Company prior to the transaction was that the subsidiary is the operator of the 2014 Eagle Ford Acquisition Properties. The Contribution is being accounted for as a business combination in accordance ASC 805 which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date.
	An allocation of the purchase price was prepared using, the year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to December 19, 2014. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Flatonia Energy, LLC tax return and certain accruals, it includes the use of estimates based on information that was available to management at the time these audited consolidated financial statements were prepared. The Company’s final allocation of purchase price is dependent on the seller’s tax return because Earthstone received carryover basis on Flatonia’s assets and liabilities because the Contribution Agreement was not a taxable transaction under the United States Internal Revenue Code of 1986, as amended. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.
	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)		$	4,046
	Asset retirement obligation			173
	Amount attributable to liabilities assumed			4,219
	Total purchase price plus liabilities assumed		$	60,644
	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)		$	4,046
	-1	The share price used for the determination of the purchase was the adjusted closing price of Common Stock on December 19, 2014, the day the Contribution closed.
	-2	This amount represents the recorded book value to tax difference of the oil and natural gas properties as of the date of the close 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; the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014 was in excess of the tax basis and as such required the recognition of a deferred tax liability.
	-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 5 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. Goodwill recognized will not be deductible for tax purposes.
	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 the beginning of the comparable prior annual reporting period, or January 1, 2013. The pro forma combined results of operations for the years ended December 31, 2014 and 2013 were been prepared by adjusting the historical results of the Company to include the historical results of the legacy Earthstone properties and the 2014 Eagle Ford Acquisition Properties. 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 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 because future events and transaction, as well as other factors (in thousands, expect 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 were 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.
For the year ended December 31, 2014, the Company recognized $0.5 million of oil, natural gas and natural gas liquids sales related to the legacy Earthstone assets and operating expenses of $0.3 million. Additionally, non-recurring transaction costs of $0.9 million were included in the consolidated statement of operations in “General and administrative” expenses; these non-recurring transaction costs have been excluded from the pro forma results for all periods presented above.
For the year ended December 31, 2014, the Company recognized $0.6 million of oil, natural gas and natural gas liquids sales related to the 2014 Eagle Ford Acquisition Properties and operating expenses of $0.1 million. Additionally, non-recurring transaction costs of $0.2 million are included in the consolidated statement of operations in “General and administrative” expenses; these non-recurring transaction costs have been excluded from the pro forma results for all periods presented above.
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 effective date of the 2013 Eagle Ford Acquisition was January 1, 2013. The estimated fair value of the properties approximates the fair value of consideration, and as a result, no goodwill was recognized.
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 5 Fair Value Adjustments.
The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2013 and 2012 as if the 2013 Eagle Ford Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2012. The pro forma combined results of operations for the years ended December 31, 2013 and 2012 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):
		Years ended December 31,
		2013					2012
		(Unaudited)
Revenue		$	48,291				$	39,804
Loss before taxes		$	(5,240	)			$	(39,796	)
Net loss available to Earthstone common stockholders		$	(3,406	)			$	(25,867	)
Pro forma net loss per common share:
Basic and diluted		$	(0.37	)			$	(2.83	)
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 and 2012 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 Statement 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” in the Consolidated Statement of Operations.
2013 Divestitures
In May 17, 2013, OVR 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. OVR recorded a loss on sale of $0.1 million. The effective date of the sale was April 1, 2013.
On March 28, 2013, OVR sold undeveloped acreage in Harrison County, Texas, and the working interest in one well for cash consideration of one hundred dollars. OVR recorded a loss on sale of $0.1 million. The effective date of the sale was April 1, 2013.
2012 Acquisitions and Divestitures
On December 18, 2012, OVE assigned all of the membership interests of one of its wholly owned subsidiaries (the “Assigned Subsidiary”) to an entity unaffiliated with OVE and OVR. The consolidated financial statements include the accounts of the Assigned Subsidiary through the date of assignment. Prior to the assignment, in February 2012, the OVR predecessor closed on a sale of all of the oil and natural gas assets of the Assigned Subsidiary for cash consideration of $8.5 million. The OVR predecessor used $5.2 million of the proceeds to pay down its credit facility and the remainder to fund capital expenditures and for general corporate purposes. The OVR predecessor recorded a $4.1 million gain on the sale.
On April 4, 2012, the OVR predecessor acquired various working interests in certain wells and undeveloped acreage in Caddo and DeSoto Parishes, Louisiana, for cash consideration of $1.6 million. The OVR predecessor acquired working interests in 19 wells, including additional interests in eight wells operated by OVO. The effective date of the acquisition was January 1, 2012.
On March 8, 2012, the OVR predecessor sold working interests and unitized producing acreage in two wells in Lincoln and Webster Parishes, Louisiana, for cash consideration of $0.1 million. The OVR predecessor recorded a gain on sale of $0.1 million. The effective date of the sale was January 1, 2012.
On March 8, 2012, the OVR predecessor sold working interests in six wells in exchange for a working interests in one well, and cash consideration received by the Company of $1.1 million. The wells are located in DeSoto Parish, Louisiana. The OVR predecessor recorded a gain on sale of $0.6 million. The effective date of the exchange was January 1, 2012.
On February 16, 2012, the OVR predecessor sold certain assets located in Ouachita Parish, Louisiana. The sale consisted of approximately 395 net acres of unproved leasehold in the Cadeville Prospect and one well in progress in exchange for cash consideration of $0.4 million. The OVR predecessor recorded a gain on sale of $0.1 million. The effective date of the sale was February 1, 2012.
On February 7, 2012, the OVR predecessor acquired working interests in certain sections of the NW Caldwell Prospect located in Caldwell County, Texas, for cash consideration of $1.0 million. The acquired leasehold added approximately 1,973 net acres of unproved leasehold to the NW Caldwell Prospect, all of which was subsequently divested on May 17, 2013. The effective date of the acquisition was January 25, 2012.

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2014
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 (“ASC Topic 815”), to account for its derivative financial instruments. The Company does not enter into derivative contracts for speculative trading purposes.
	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” on the Consolidated Statements of Operations. All derivative contracts are recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.
	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, 2014:
	Period	Instrument	Commodity		Volume in				Fixed Price
					MMBtu / Bbls
	January 2015 - March 2015	Swap	Natural Gas			150,000			$	4.175
	January 2015 - March 2015	Swap	Natural Gas			75,000			$	4.3
	January 2015 - June 2015	Swap	Crude Oil			21,000			$	91.5
	January 2015 - December 2015	Swap	Crude Oil			66,000			$	95.1
	In March 2015, the Company entered into a crude oil swap contract.  The crude oil swap has a term of April 2015 through March 2016 and provides 5,000 Bbls per month.  The swap has a fixed price of $57.00 per Bbl.
	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 as of December 31, 2014 and 2013 (in thousands):
			31-Dec-14											31-Dec-13
	Derivatives not	Balance Sheet Location	Gross						Gross			Net		Gross			Gross		Net
	designated as hedging		Recognized						Amounts			Recognized		Recognized			Amounts		Recognized
	contracts under ASC		Assets /						Offset			Assets /		Assets /			Offset		Assets /
	Topic 815		Liabilities									Liabilities		Liabilities					Liabilities
	Commodity contracts	Current derivative assets	$	3,569					$		—	$	3,569	$	154		$	—	$	154
	Commodity contracts	Current derivative liabilities	$	—					$		—	$	—	$	(172	)	$	—	$	(172	)
	Commodity contracts	Noncurrent derivative liabilities	$	—					$		—	$	—	$	(28	)	$	—	$	(28	)
	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,
			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	$	3,614			$	(45	)
	Realized gain on commodity contracts	Net gain on derivative contracts	$	778			$	341
			$	4,392			$	296
	The Company did not have derivative contracts as of December 31, 2012.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 5. Fair Value Measurements
	FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.
	The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC 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, 2014.
	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):
	31-Dec-14	Level 1		Level 2		Level 3		Total
	Financial assets
	Current derivative assets	$	—	$	3,569	$	—	$	3,569
	Total financial assets	$	—	$	3,569	$	—	$	3,569
	Financial liabilities
	Current derivative liabilities	$	—	$	—	$	—	$	—
	Noncurrent derivative liabilities		—		—		—		—
	Total financial liabilities	$	—	$	—	$	—	$	—
	31-Dec-13
	Financial assets
	Current derivative assets	$	—	$	154	$	—	$	154
	Total financial assets	$	—	$	154	$	—	$	154
	Financial liabilities
	Current derivative liabilities	$	—	$	172	$	—	$	172
	Noncurrent derivative liabilities		—		28		—		28
	Total financial liabilities	$	—	$	200	$	—	$	200
	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
	Asset Impairment
	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 $16.9 million, $9.8 million and $43.9 million on proved properties during the years ended December 31, 2014, 2013, and 2012, respectively.
	The Company recorded asset impairments of $2.5 million, $2.5 million, and $8.6 million on unproved properties during the years ended December 31, 2014, 2013, and 2012, respectively. All of the 2014, 2013, and 2012 impairments were included in impairment expense.
	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 9, “Asset Retirement Obligations” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

Equity

Equity	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Equity	Note 6. 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 7” Stock Based Compensation”.   The Company had no outstanding common stock equivalents for the years ended December 31, 2014, 2013, and 2012.
	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 years ended December 31, 2013 and 2012, reflect the shares issued to Oak Valley Resources, LLC 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)	2014			2013			2012
	Net loss	$	(28,834	)	$	(19,875	)	$	(53,321	)
	Weighted average common shares outstanding:
	Basic		9,279			9,124			9,124
	Diluted		9,279			9,124			9,124
	Net loss per share:
	Basic	$	(3.11	)	$	(2.18	)	$	(5.84	)
	Diluted	$	(3.11	)	$	(2.18	)	$	(5.84	)
	Members’ Equity
	As was explained in Note 2 – Summary of Significant Account Policies – Principles of Consolidation the historical financial information contained in the Annual Report on Form 10-K is that of OVR and its subsidiaries. OVR was formed on December 14, 2012. On December 21, 2012, OVR was capitalized by affiliates of EnCap via the contribution of certain oil and gas properties which were conveyed by assigning 100% of the issued and outstanding membership interests in ECC VI, LLC and 100% of the issued and outstanding membership interest in Oak Valley Energy, LLC in exchange for membership interests in OVR. Also on December 21, 2012, EnCap, Wells Fargo, VILLco, and OVM committed an aggregate of $150.0 million in exchange for additional membership interests in OVR. On April 25, 2013, OVR closed a private placement offering amongst accredited investors that raised $62.8 million in capital commitments in exchange for membership interests in OVM. During 2013 OVM members committed an additional $1.7 million (collectively “Investors”).
	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, par value $0.001 per share 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, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock Based Compensation	Note 7. 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.  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 Company employees or those of 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 750,000 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, 2014, there were no shares issued and all 750,000 shares remained available for award.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Note 8. Long-Term Debt
	On June 29, 2011, OVE entered into a new four-year senior secured revolving credit facility (the “OVE Credit Facility”). The OVE Credit Facility was subsequently assumed by OVR on December 21, 2012 (the “OVR Credit Facility”), the date upon which all of the membership interests in OVE were assigned to OVR.  In connection with the closing of the Exchange on December 19, 2014, the Company entered into a new credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “ESTE Credit Facility”).  The OVR Credit facility was refinanced under the “ESTE Credit Facility” and the legacy credit facility of the Company was paid in full and terminated. OVR also assigned to the Company its commodity derivative contracts, which were provided for under the OVR Credit Facility.
	Outstanding borrowings under the OVR Credit Facility and the OVE Credit Facility had annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus the applicable utilization margin of 2.25% to 4.25% (2.42% and 2.96% at December 31, 2013 and 2012, respectively) or (b) the base rate plus the applicable utilization margin of 1.00% to 3.00% (4.25% and 4.75% at December 31, 2013 and 2012, respectively). The commitment rate was 0.500% on all unused borrowings.
	The initial borrowing base of the ESTE Credit Facility is $80.0 million and is subject to redetermination on the first business day of May and November of each year. At the option of the borrower, the amounts borrowed under the credit agreement bear annual interest rates at either (a) LIBOR plus the applicable utilization margin of 1.50% to 2.50% (1.664% at December 31, 2014) or (b) the base rate plus the applicable utilization margin of 0.50% to 1.50% (3.75% at December 31, 2014). 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. Additional payments due under the credit agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate ranges from 0.375% to 0.50% per year, depending upon the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees.
	As of December 31, 2014, the Company had $11.2 million of debt outstanding, bearing an interest rate of 1.664%, $0.3 million of letters of credit outstanding and $68.5 million of borrowing base available under its ESTE Credit Facility.
	All of the credit facilities discussed herein contain 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 current ratio 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, 2014, the Company was in compliance with these covenants under the ESTE Credit Facility.
	Interest expense for 2014, 2013 and 2012 includes amortization of deferred financing costs of $0.2 million, $0.1 million, and $48,000, respectively.   $1.0 million and $0.5 million, net of amortization, associated with the Company’s credit facilities have been capitalized as of December 31, 2014 and 2013, respectively, and are amortized on a straight-line basis over the term of the credit agreements.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 9. 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” in the Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.
	The following table summarizes the Company’s asset retirement obligation transactions recorded during 2014 and 2013, and in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (in thousands):
		2014			2013
	Beginning asset retirement obligations	$	3,011		$	3,938
	Acquisitions(1)		2,742			609
	Liabilities incurred		64			316
	Accretion expense		317			217
	Disposal of properties		(56	)		(110	)
	Revision of estimates		—			(1,959	)
	Ending asset retirement obligations	$	6,078		$	3,011
	(1) See Note 3, "Acquisitions and Divestitures" for additional information on the Company's acquisition activities.
	Based on expected timing of settlement, $0.4 million of the asset retirement obligation is classified as current at December 31, 2014. At December 31, 2013, $70,000 was classified as current.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Note 10. Related Party Transactions
	FASB ASC Topic 850, Related Party Disclosures (“ASC Topic 850”), requires that transactions with related parties that would make a difference in decision making be disclosed so that users of the financial statements can evaluate their significance. EnCap, the members of OVM, and OVR’s Private Placement Investors are considered related parties under ASC Topic 850. The following are significant related party transactions between the Company and parties of Encap and the members of OVM as of and for the years ended December 31, 2014, 2013, and 2012 as well as significant related party transactions between the Company and the OVR Private Placement Investors as of and for the years ended December 31, 2014 and 2013.
	The Company employs members of OVM. For the years ended December 31, 2014, 2013 and 2012, the Company made payments totaling $3.9 million, $2.2 million and $0.3 million, respectively, to these members as compensation for services and reimbursement of expenses. The payments are included in “General and administrative expense” on the Consolidated Statements of Operations or have been charged out to oil and gas properties.
	At December 31, 2013, the Company had a liability of $0.7 million due to members of OVM, which is included in “Accrued expenses” on the Consolidated Balance Sheet. At December 31, 2014, the Company did not have a related party asset due from OVM members or a related party liability due to OVM members.
	At December 31, 2014 and 2013, the Company had a liabilities of $2.3 million and $0.6 million, respectively, due to companies to which certain members of OVR are significant related parties.  These amounts are included in “Accounts payable” on the Consolidated Balance Sheet.
	As described in Note 6, “Equity”, all of the authorized Class C Units were issued to OVM. Class C Units entitle OVM to receive distributions from the Company if certain previously agreed upon equity returns are achieved.
	As described in Note 2 “Summary of Significant Accounting Policies”, on December 21, 2012, EnCap assigned all the membership interests in ECC VI and OVE to the Company. These transfers were recorded by the Company at the carrying amounts of the assets and liabilities contributed.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 11. 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, 2014 (in thousands):
		2015		2016		2017		2018		2019		Thereafter
	Drilling contracts*	$	8,682	$	8,845	$	—	$	—	$	—	$	—
	Gas contract**		1,643		1,647		1,643		1,643		1,643		2,327
	Office leases		715		639		609		619		575		—
	Total	$	11,040	$	11,131	$	2,252	$	2,262	$	2,218	$	2,327
	*As of December 31, 2014, the Company had three drilling rigs under contract, of which two contracts have since concluded (January 2015 and February 2015) and the rigs were released as the Company had met all of its contractually agreed to terms within each contract. In 2014, the Company entered into an 18 month contract for a new rig currently being built.  The contract provides for a daily drilling rate of $29,000 and in the event the Company does not fulfill its contractual obligations, liquidated damages of up to $10.9 million subject to adjustments could be charged.  The rig is scheduled to be completed during the second quarter 2015.  As of December 31, 2014, the minimum commitment per the terms of the agreement is approximately $16.0 million.
	**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 Houston, Texas and Denver, Colorado.  Rent expense was approximately $0.4 million, $0.1 million, and $0.1 million for the years ended December 31, 2014, 2013, and 2012, respectively.  As of December 31, 2014, minimum future lease commitments for subsequent annual periods for all non-cancelable operating leases was approximately $3.2 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. As of December 31, 2014, and through the filing date of this report, the Company does not believe the ultimate resolution of such actions or potential actions of which the Company is currently aware will have a material effect on its consolidated financial position or results of operations.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Note 12: Income Taxes
	As a partnership, OVR was generally not subject to Federal or state income tax on its taxable income. The Partnership’s taxable income and deductions were reported by the partners in their respective returns. Therefore, no income taxes were reported by OVR prior to merger date.
	The following table shows the components of the Company’s income tax provision for 2014 (in thousands):
	Current:
	Federal	$	—
	State		—
	Total current		—
	Deferred:
	Federal		21,803
	State		302
	Total deferred		22,105
	Total income tax provision	$	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 year ended December 31, 2014 (in thousands, except percentages):
	Net loss before income taxes	$	(6,729	)
	Tax benefit computed at Federal statutory rate		(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
	State income taxes, net of Federal benefit		188
	Total income tax expense	$	22,105
	Effective tax rate		-329	%
	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, 2014 are as follows (in thousands):
	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		(381	)
	Oil & gas properties		(29,730	)
	Asset retirement obligation		1,952
	Intangible assets		130
	Unrealized derivative gain		(1,229	)
	Net deferred noncurrent tax assets (liabilities)		(29,258	)
	Net deferred tax liability	$	(29,032	)
	As of December 31, 2014, the Company had statutory depletion available for carryforward of approximately $6.3 million, which may be used to offset future taxable income. The amount that may be used in any year is subject to an annual limit of $1.0 million arising from a change in control in 2014.
	Uncertain Tax Positions
	ASC 740, Income Taxes (ASC 740) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As of December 31, 2014, the Company has no material uncertain tax positions. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.
	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, 2014, 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_Quarterl

Supplemental Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Supplemental Selected Quarterly Financial Data (Unaudited)	Note 13.  Supplemental Selected Quarterly Financial Data (Unaudited)
		Three Months Ended,
	(In thousands, except per share data)	March 31,			June 30,			September 30,			December 31,
		2014			2014			2014			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			9,192			10,204			31,407
	Operating income (loss)		3,909			2,953			1,851			(19,299	)
	Other income (expense), net		(1,169	)		(1,424	)		2,364			4,086
	Income tax expense		—			—			—			(22,105	)
	Net income (loss)	$	2,740		$	1,529		$	4,215		$	(37,318	)
	Basic net income (loss) per share	$	0.3		$	0.17		$	0.46		$	(3.83	)
	Diluted net income ( loss) per share	$	0.3		$	0.17		$	0.46		$	(3.83	)
		Three Months Ended,
	(In thousands, except per share data)	March 31,			June 30,			September 30,			December 31,
		2013			2013			2013			2013
	Year Ended December 31, 2013
	Oil and gas revenues	$	3,110		$	6,209		$	11,208		$	9,107
	Other revenues		116			80			96			17
	Operating expenses		7,049			10,696			10,095			21,803
	Operating (loss) income		(3,823	)		(4,407	)		1,209			(12,679	)
	Other (expense) income, net		(141	)		232			(91	)		(175	)
	Net (loss) income	$	(3,964	)	$	(4,175	)	$	1,118		$	(12,854	)
	Basic net (loss) income per share	$	(0.43	)	$	(0.46	)	$	0.12		$	(1.41	)
	Diluted net (loss) income per share	$	(0.43	)	$	(0.46	)	$	0.12		$	(1.41	)

Supplemental_Information_On_Oi

Supplemental Information On Oil And Gas Exploration And Production Activities	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Oil and Gas Exploration and Production Industries Activities	SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
	Costs Incurred Related to Oil and Gas Activities
	The Company’s oil and gas activities for 2014, 2013 and 2012 were entirely within the United States of America. Costs incurred in oil and gas producing activities were as follows (in thousands):
			Year Ended December 31,
			2014 (1)				2013			2012
	Acquisition cost:
	Proved		$	74,728			$	51,488		$	1,609
	Unproved			36,236				32,863			11,589
	Exploration costs:
	Exploratory drilling			-				64			2,013
	Geological and geophysical			111				394			-
	Development costs			75,105				32,511			24,222
	Total additions		$	186,180			$	117,320		$	39,433
	-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, 2014, 2013 and 2013, additions to oil and gas properties of $0.2 million. $1.0 million and $0.1 million 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):
	Oil and Natural Gas Reserves
		December 31,
		2014				2013			2012
	Balance, beginning of year	$	-			$	2,032		$	19
	Additions to capitalized exploratory well costs pending
	the determination of proved reserves		-				64			2,013
	Capitalized exploratory well costs charged to expense		-				(2,096	)		-
	Balance, end of year	$	-			$	-		$	2,032
	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, 2014, 2013 and 2012 have been independently prepared by Cawley, Gillespie & Associates, Inc.
	The reserve information in this Annual Report on Form 10-K 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 price as of December 31, 2014, 2013, and 2012 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 $94.99 per barrel, $96.94 per barrel, and $94.71 per barrel, respectively. The natural gas prices as of December 31, 2014, 2013 and 2012 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $4.309 per MMBtu, $3.666 per MMBtu and $2.752 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, 2014, 2013 and 2012 are as follows:
		Oil				Natural Gas			NGLs			Total
		(MBbl)				(MMcf)			(MBbl)			(MBOE)
	Balance - December 31, 2011		1,182				56,459			-			10,592
	Extensions and discoveries		407				3,596			299			1,306
	Sale of minerals in place		(301	)			(165	)		-			(329	)
	Production		(90	)			(2,298	)		(76	)		(549	)
	Revision to previous estimates		(679	)			(47,493	)		169			(8,426	)
	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
	Proved developed reserves:
	31-Dec-12		296				8,245			268			1,938
	31-Dec-13		1,307				11,053			557			3,706
	31-Dec-14		6,093				16,214			1,005			9,800
	Proved undeveloped reserves:
	31-Dec-12		223				1,854			124			656
	31-Dec-13		4,771				13,160			761			7,725
	31-Dec-14		7,710				22,365			954			12,392
	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.
	The total proved reserves decrease of 8.0 MMBoe during 2012 is comprised of a decrease of 1.6 MMBoe in proved developed and 6.4 MMBoe in proved undeveloped reserves.
	During 2012, the Company added 1.3 MMBoe in proved reserves due to successful drilling in it non-operated Eagle Ford property. The Company also sold reserves in place of approximately 0.3 MMBoe and had a downward revision of previous estimates of approximately 8.4 MMBoe. The downward revision was primarily attributable to lower natural gas prices incorporated into the Company’s reserve estimates at December 31, 2012 as compared to December 31, 2011.
	At December 31, 2014 the Company’s estimated proved undeveloped reserves (PUDs) were 12.4 MMBoe, a 4.7 MMBoe net increase over the previous year’s estimate of 7.7 MMBoe. The following details the changes in PUD reserves for 2014 (MBoe):
Beginning proved undeveloped reserves at December 31, 2013			7,725
Undeveloped reserves transfer to developed			(1,306	)
Revisions			672
Purchases			4,451
Extensions and discoveries			850
Ending proved undeveloped reserves at December 31, 2014			12,392
The majority being 63%, of the Company’s PUDs that were transferred from PUD to the developed reserve category occurred in its Eagle Ford property in Fayette and Gonzales counties, TX. The remaining amount that was transferred was in the Company’s non-operated Eagle Ford project in La Salle County, TX.
All of the Company’s increases through extensions and discoveries occurred in our operated Eagle Ford property in Fayette and Gonzales counties, TX as a result of successful drilling during 2014 which added additional PUD locations as well.
During 2014 we purchased PUD reserves of 4.5 MMBoe as a result of the Exchange Agreement whereby Oak Valley acquired the legacy Earthstone assets and the Contribution Agreement where the Company acquired additional interests in its operated Eagle Ford property.
The revisions to PUD reserves of 672 MBOE occurred primarily as a result of increased gas prices from December 31, 2013 to December 31, 2014 from $3.666/MMBTU to $4.309/MMBTU which increased the number of economic gas-weighted PUD locations and reserves of approximately 1,014 MBOE.  This increase was offset by revisions to oil-weighted PUDs related to offsetting producing well performance as well as a decrease in oil prices between December 31, 2013 and December 31, 2014 from $96.94/BO to $94.99/BO.
Based on the Company’s year-end 2014 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 (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s third party engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.
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, 2014, 2013 and 2012, 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,
	2014				2013			2012
Future cash inflows	$	1,464,138			$	718,049		$	88,234
Future production costs		(427,113	)			(202,957	)		(32,967	)
Future development costs		(312,010	)			(220,828	)		(15,271	)
Future income tax expense		(180,248	)			-			-
Future net cash flows		544,767				294,264			39,996
10% annual discount for estimated timing of cash flows		(288,911	)			(168,907	)		(14,864	)
Standardized measure of discounted future cash flows	$	255,856			$	125,357		$	25,132
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, 2014 (in thousands):
	December 31,
	2014				2013			2012
Beginning of year	$	125,357			$	25,132		$	69,240
Sales of oil and gas produced, net of production costs		(35,794	)			(20,287	)		(10,300	)
Sales of minerals in place		-				(380	)		(10,274	)
Net changes in prices and production costs		(34,681	)			241			(6,133	)
Extensions, discoveries, and improved recoveries		54,157				48,006			16,375
Changes in income taxes, net (1)		(88,944	)			-			-
Previously estimated development costs incurred during the period		18,252				3,227			-
Net changes in future development costs		7,028				(22,966	)		14,787
Purchases of minerals in place		163,309				56,069			-
Revisions of previous quantity estimates		16,283				26,259			(54,775	)
Accretion of discount		12,536				2,513			6,924
Changes in timing of estimated cash flows and other		18,353				7,543			(712	)
End of year	$	255,856			$	125,357		$	25,132
-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, is a partnership for federal tax purposes and is not subject to federal income taxes or state or local income taxes that follow the federal treatment, and therefore OVR did not pay or accrue for such taxes. Pursuant to the Exchange OVR’s subsidiaries have become subsidiaries of Earthstone Energy, Inc., which is a taxable entity; as such estimated tax expense was included in the Standardized Measure for December 31, 2014.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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. Prior to being capitalized on December 21, 2012, all of the Company’s wholly owned subsidiaries were controlled by EnCap. All of the companies included in the transaction had fiscal years ending December 31. The consolidated financial statements for the period ended December 31, 2012 were prepared by combining all the previously separate subsidiaries in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC Topic 805”). ASC Topic 805 states that if a transaction combines two or more commonly controlled entities that historically have not been presented together, the resulting financial statements for those periods presented require retrospective presentation of the financial statements for all the periods presented, as if the combination had been in effect since the inception of common control.
	When accounting for a transfer of assets or exchange of equity interests between entities under common control, the entity that receives the net assets or the equity interests should initially measure the assets and liabilities transferred at their historical carrying amounts. Therefore, the net assets included in the accompanying consolidated financial statements are shown at their historical carrying value.
	On December 18, 2012, prior to the assignment of membership interests of Oak Valley Energy, LLC, a Delaware Limited Liability Company (“OVE”), to the Company, one of OVE’s subsidiaries was transferred to a non-affiliated entity. In accordance with ASC Topic 805, the consolidated financial statements include the activities of that subsidiary through the date of transfer. The amount of revenue and net income from the OVE subsidiary included in the Company’s Consolidated Statement of Operations for the year ended December 31, 2012, was $4.2 million and $2.4 million, respectively. Please see Note 3 “Acquisitions and Divestitures” for more information on this transfer.
	As of December 31, 2014, the Company’s wholly-owned subsidiaries included:
	þ	Oak Valley Operating, LLC, a Texas limited liability company formed on May 26, 2011. OVO serves as the operator on all Company-operated properties in Fayette and Gonzales Counties, Texas, Louisiana and Oklahoma;
	þ	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;
	þ	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, Louisiana and Oklahoma.
	þ	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.
	All intercompany accounts and transactions are eliminated in consolidation.
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 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. Estimates and assumptions that, in the opinion of the Company’s management, are significant include oil and natural gas reserves and the related cash flow estimates used in depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, fair value estimates, asset retirement obligations, oil and natural gas revenue accruals, lease operating expense accruals, and capital accruals. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.
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 NGL purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and NGL 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, 2014, 2013, and 2012, the Company did not have an allowance for doubtful accounts as all accounts receivable were deemed collectible by management.
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 its balance sheet. 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” in the Consolidated Statement of Operations as unrealized gains or losses on derivative contracts.  Realized gains or losses on derivative contracts are also recognized in “Net gain (loss) on derivative contracts” in the Consolidated Statements of Operations.
Proved Oil and Gas Properties	Proved Oil and Gas Properties
	The Company follows the successful efforts method of accounting for its oil and gas properties. Costs incurred by the Company related to the acquisition of oil and gas properties and the cost of drilling development wells and successful exploratory wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale of oil and gas properties, the costs and related accumulated depreciation, depletion, and amortization are eliminated from the accounts and the resulting gain or loss is recognized.
	Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. 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” financial statement line item on the Consolidated Statements of Cash Flows. Gains and losses arising from the sale of properties are included in operating income (loss) on the Consolidated Statement of Operations.
	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 $18.1 million, $16.9 million, and $12.2 million, for the years ended December 31, 2014, 2013, and 2012, respectively.
	Proved oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the expected future cash flow expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, then the carrying value is written down to its estimated fair value.
	Each component of an impairment calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, estimated future net cash flows, and fair value. The Company recognized impairments of $16.9 million, $9.8 million, and $43.9 million for the years ended December 31, 2014, 2013, and 2012, respectively, on proved oil and gas properties.
Unproved Oil and Gas Properties	Unproved Oil and Gas 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” financial statement line item on the Consolidated Statements of Cash Flows. Unproved oil and gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.
	Unproved properties are assessed periodically to determine whether they have been impaired based on remaining lease term, drilling results, reservoir performance, seismic interpretation, or future plans to develop acreage.
	The Company recognized impairments of $2.5 million, $2.5 million, and $8.6 million for the years ended December 31, 2014, 2013, and 2012, respectively, on unproved oil and gas properties.
Goodwill	Goodwill
	We account for goodwill in accordance with ASC 350, Intangibles—Goodwill and Other (ASC 350). Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. The company carried goodwill as of December 31, 2014 related to the reverse acquisition with Earthstone and the 2014 Eagle Ford Acquisition.  See Note 3 “Acquisitions and Divestitures” for further discussion regarding the goodwill associated with the transactions.
	Accounting Standards Update (ASU) No. 2011-08, Testing for Goodwill Impairment (ASU 2011-08), simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying value. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test. However, if the same conclusion is not reached, the entity is required to perform the first step of the two-step impairment test. In this step, the fair value of the reporting unit is calculated and compared to the carrying value of the reporting unit. If the carrying value exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of impairment loss, if any. ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test.
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 9 “Asset Retirement Obligations” for further disclosure regarding the asset retirement obligation.
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 ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved oil and gas property as business combinations.
Revenue Recognition	Revenue Recognition
	Oil, natural gas, and NGL revenues represent income from production and delivery of oil, natural gas, and NGL, 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, 2014, 2013, or 2012.
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 NGL 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 2014 and 2013, one purchaser accounted for 60% and 21%, of the Company’s oil, natural gas, and NGL revenues, respectively. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and NGL revenues during 2014, 2013, and 2012.
	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 NGL to the purchaser, collects the cash, and distributes the cash to the Company. The Company recognizes the cash received as revenue. In 2014, one operator distributed 20% of the Company’s oil, natural gas and NGL revenues.  In 2013, two operators distributed 47% and 11% of the Company’s oil, natural gas, and NGL revenues. In 2012, two operators distributed 65% and 18% of the Company’s oil, natural gas, and NGL revenues. No other operator accounted for 10% or more of the Company’s oil, natural gas, and NGL revenues during 2013, 2012, and 2011.
	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 two counterparties. Both counterparties are participants in the Company’s credit facility and possess 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 bank 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. Deferred tax assets and liabilities are included in the 2014 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 is provided for deferred tax assets not expected to be realized.  As noted in the Principles of Consolidation the historical financials are those of OVR. OVR is 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 (“ASC Topic 740”), relating to accounting for uncertainties in income taxes. ASC Topic 740 clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. ASC Topic 740 requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. ASC Topic 740 also provides guidance on measurement, classification, interest and penalties and disclosure. Tax positions taken related to the Company’s pass-through status and state income tax liability, including deductibility of expenses, have been reviewed and the Company’s management is of the opinion that material positions taken by the Company would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2014, 2013, or 2012. The 2011 through 2014 tax years generally remain subject to examination.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements
	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 around contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. The standards update is effective for interim and annual periods beginning after December 15, 2016. We will adopt this standards update, as required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact, if any, of this guidance on its consolidated financial statements.

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2014
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)	$	4,046
	Asset retirement obligation		173
	Amount attributable to liabilities assumed		4,219
	Total purchase price plus liabilities assumed	$	60,644
	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)	$	4,046
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 the beginning of the comparable prior annual reporting period, or January 1, 2013. The pro forma combined results of operations for the years ended December 31, 2014 and 2013 were been prepared by adjusting the historical results of the Company to include the historical results of the legacy Earthstone properties and the 2014 Eagle Ford Acquisition Properties. 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 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 because future events and transaction, as well as other factors (in thousands, expect 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 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):
		Years ended December 31,
		2013					2012
		(Unaudited)
	Revenue	$	48,291				$	39,804
	Loss before taxes	$	(5,240	)			$	(39,796	)
	Net loss available to Earthstone common stockholders	$	(3,406	)			$	(25,867	)
	Pro forma net loss per common share:
	Basic and diluted	$	(0.37	)			$	(2.83	)
Schedule of Consideration Paid to Acquire and Amounts of Assets Acquired and Liabilities Assumed
	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
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	$	7,852
	Long-term debt		7,000
	Deferred tax liability (2)		2,880
	Asset retirement obligation		2,227
	Amount attributable to liabilities assumed		19,959
	Total purchase price plus liabilities assumed	$	53,414
	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)	$	18,946

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014:
	Period	Instrument	Commodity		Volume in				Fixed Price
					MMBtu / Bbls
	January 2015 - March 2015	Swap	Natural Gas			150,000			$	4.175
	January 2015 - March 2015	Swap	Natural Gas			75,000			$	4.3
	January 2015 - June 2015	Swap	Crude Oil			21,000			$	91.5
	January 2015 - December 2015	Swap	Crude Oil			66,000			$	95.1
	In March 2015, the Company entered into a crude oil swap contract.  The crude oil swap has a term of April 2015 through March 2016 and provides 5,000 Bbls per month.  The swap has a fixed price of $57.00 per Bbl.
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 as of December 31, 2014 and 2013 (in thousands):
			31-Dec-14											31-Dec-13
	Derivatives not	Balance Sheet Location	Gross						Gross			Net		Gross			Gross		Net
	designated as hedging		Recognized						Amounts			Recognized		Recognized			Amounts		Recognized
	contracts under ASC		Assets /						Offset			Assets /		Assets /			Offset		Assets /
	Topic 815		Liabilities									Liabilities		Liabilities					Liabilities
	Commodity contracts	Current derivative assets	$	3,569					$		—	$	3,569	$	154		$	—	$	154
	Commodity contracts	Current derivative liabilities	$	—					$		—	$	—	$	(172	)	$	—	$	(172	)
	Commodity contracts	Noncurrent derivative liabilities	$	—					$		—	$	—	$	(28	)	$	—	$	(28	)
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,
			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	$	3,614			$	(45	)
	Realized gain on commodity contracts	Net gain on derivative contracts	$	778			$	341
			$	4,392			$	296

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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):
	31-Dec-14	Level 1		Level 2		Level 3		Total
	Financial assets
	Current derivative assets	$	—	$	3,569	$	—	$	3,569
	Total financial assets	$	—	$	3,569	$	—	$	3,569
	Financial liabilities
	Current derivative liabilities	$	—	$	—	$	—	$	—
	Noncurrent derivative liabilities		—		—		—		—
	Total financial liabilities	$	—	$	—	$	—	$	—
	31-Dec-13
	Financial assets
	Current derivative assets	$	—	$	154	$	—	$	154
	Total financial assets	$	—	$	154	$	—	$	154
	Financial liabilities
	Current derivative liabilities	$	—	$	172	$	—	$	172
	Noncurrent derivative liabilities		—		28		—		28
	Total financial liabilities	$	—	$	200	$	—	$	200

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Reconciliation of Net Income and Weighted-Average Common Shares Outstanding for Calculating Basic and Diluted Loss Per 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 7” Stock Based Compensation”.   The Company had no outstanding common stock equivalents for the years ended December 31, 2014, 2013, and 2012.
	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 years ended December 31, 2013 and 2012, reflect the shares issued to Oak Valley Resources, LLC 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)	2014			2013			2012
	Net loss	$	(28,834	)	$	(19,875	)	$	(53,321	)
	Weighted average common shares outstanding:
	Basic		9,279			9,124			9,124
	Diluted		9,279			9,124			9,124
	Net loss per share:
	Basic	$	(3.11	)	$	(2.18	)	$	(5.84	)
	Diluted	$	(3.11	)	$	(2.18	)	$	(5.84	)

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Summary of Asset Retirement Obligation Transactions	The following table summarizes the Company’s asset retirement obligation transactions recorded during 2014 and 2013, and in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (in thousands):
		2014			2013
	Beginning asset retirement obligations	$	3,011		$	3,938
	Acquisitions(1)		2,742			609
	Liabilities incurred		64			316
	Accretion expense		317			217
	Disposal of properties		(56	)		(110	)
	Revision of estimates		—			(1,959	)
	Ending asset retirement obligations	$	6,078		$	3,011
	(1) See Note 3, "Acquisitions and Divestitures" for additional information on the Company's acquisition activities.

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Future minimum payments	The following table summarizes the Company’s estimated future contractual commitments as of December 31, 2014 (in thousands):
		2015		2016		2017		2018		2019		Thereafter
	Drilling contracts*	$	8,682	$	8,845	$	—	$	—	$	—	$	—
	Gas contract**		1,643		1,647		1,643		1,643		1,643		2,327
	Office leases		715		639		609		619		575		—
	Total	$	11,040	$	11,131	$	2,252	$	2,262	$	2,218	$	2,327

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Components of Income Tax Provision	The following table shows the components of the Company’s income tax provision for 2014 (in thousands):
	Current:
	Federal	$	—
	State		—
	Total current		—
	Deferred:
	Federal		21,803
	State		302
	Total deferred		22,105
	Total income tax provision	$	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 year ended December 31, 2014 (in thousands, except percentages):
	Net loss before income taxes	$	(6,729	)
	Tax benefit computed at Federal statutory rate		(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
	State income taxes, net of Federal benefit		188
	Total income tax expense	$	22,105
	Effective tax rate		-329	%
Components of Deferred Tax Assets and Liabilities	Significant components of the deferred tax assets and liabilities at December 31, 2014 are as follows (in thousands):
	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		(381	)
	Oil & gas properties		(29,730	)
	Asset retirement obligation		1,952
	Intangible assets		130
	Unrealized derivative gain		(1,229	)
	Net deferred noncurrent tax assets (liabilities)		(29,258	)
	Net deferred tax liability	$	(29,032	)

Supplemental_Selected_Quarterl1

Supplemental Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Selected Quarterly Financial Data
		Three Months Ended,
	(In thousands, except per share data)	March 31,			June 30,			September 30,			December 31,
		2014			2014			2014			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			9,192			10,204			31,407
	Operating income (loss)		3,909			2,953			1,851			(19,299	)
	Other income (expense), net		(1,169	)		(1,424	)		2,364			4,086
	Income tax expense		—			—			—			(22,105	)
	Net income (loss)	$	2,740		$	1,529		$	4,215		$	(37,318	)
	Basic net income (loss) per share	$	0.3		$	0.17		$	0.46		$	(3.83	)
	Diluted net income ( loss) per share	$	0.3		$	0.17		$	0.46		$	(3.83	)
		Three Months Ended,
	(In thousands, except per share data)	March 31,			June 30,			September 30,			December 31,
		2013			2013			2013			2013
	Year Ended December 31, 2013
	Oil and gas revenues	$	3,110		$	6,209		$	11,208		$	9,107
	Other revenues		116			80			96			17
	Operating expenses		7,049			10,696			10,095			21,803
	Operating (loss) income		(3,823	)		(4,407	)		1,209			(12,679	)
	Other (expense) income, net		(141	)		232			(91	)		(175	)
	Net (loss) income	$	(3,964	)	$	(4,175	)	$	1,118		$	(12,854	)
	Basic net (loss) income per share	$	(0.43	)	$	(0.46	)	$	0.12		$	(1.41	)
	Diluted net (loss) income per share	$	(0.43	)	$	(0.46	)	$	0.12		$	(1.41	)

Supplemental_Information_On_Oi1

Supplemental Information On Oil And Gas Exploration And Production Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Costs Incurred in Oil and Gas Producing Activities	The Company’s oil and gas activities for 2014, 2013 and 2012 were entirely within the United States of America. Costs incurred in oil and gas producing activities were as follows (in thousands):
			Year Ended December 31,
			2014 (1)				2013			2012
	Acquisition cost:
	Proved		$	74,728			$	51,488		$	1,609
	Unproved			36,236				32,863			11,589
	Exploration costs:
	Exploratory drilling			-				64			2,013
	Geological and geophysical			111				394			-
	Development costs			75,105				32,511			24,222
	Total additions		$	186,180			$	117,320		$	39,433
	þ	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):
	Oil and Natural Gas Reserves
		December 31,
		2014				2013			2012
	Balance, beginning of year	$	-			$	2,032		$	19
	Additions to capitalized exploratory well costs pending
	the determination of proved reserves		-				64			2,013
	Capitalized exploratory well costs charged to expense		-				(2,096	)		-
	Balance, end of year	$	-			$	-		$	2,032
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, 2014, 2013 and 2012 are as follows:
		Oil				Natural Gas			NGLs			Total
		(MBbl)				(MMcf)			(MBbl)			(MBOE)
	Balance - December 31, 2011		1,182				56,459			-			10,592
	Extensions and discoveries		407				3,596			299			1,306
	Sale of minerals in place		(301	)			(165	)		-			(329	)
	Production		(90	)			(2,298	)		(76	)		(549	)
	Revision to previous estimates		(679	)			(47,493	)		169			(8,426	)
	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
	Proved developed reserves:
	31-Dec-12		296				8,245			268			1,938
	31-Dec-13		1,307				11,053			557			3,706
	31-Dec-14		6,093				16,214			1,005			9,800
	Proved undeveloped reserves:
	31-Dec-12		223				1,854			124			656
	31-Dec-13		4,771				13,160			761			7,725
	31-Dec-14		7,710				22,365			954			12,392
Changes in PUD reserves	Beginning proved undeveloped reserves at December 31, 2013			7,725
	Undeveloped reserves transfer to developed			(1,306	)
	Revisions			672
	Purchases			4,451
	Extensions and discoveries			850
	Ending proved undeveloped reserves at December 31, 2014			12,392
Schedule Of Standardized Measure	The Standardized Measure is as follows (in thousands):
		December 31,
		2014				2013			2012
	Future cash inflows	$	1,464,138			$	718,049		$	88,234
	Future production costs		(427,113	)			(202,957	)		(32,967	)
	Future development costs		(312,010	)			(220,828	)		(15,271	)
	Future income tax expense		(180,248	)			-			-
	Future net cash flows		544,767				294,264			39,996
	10% annual discount for estimated timing of cash flows		(288,911	)			(168,907	)		(14,864	)
	Standardized measure of discounted future cash flows	$	255,856			$	125,357		$	25,132
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, 2014 (in thousands):
		December 31,
		2014				2013			2012
	Beginning of year	$	125,357			$	25,132		$	69,240
	Sales of oil and gas produced, net of production costs		(35,794	)			(20,287	)		(10,300	)
	Sales of minerals in place		-				(380	)		(10,274	)
	Net changes in prices and production costs		(34,681	)			241			(6,133	)
	Extensions, discoveries, and improved recoveries		54,157				48,006			16,375
	Changes in income taxes, net (1)		(88,944	)			-			-
	Previously estimated development costs incurred during the period		18,252				3,227			-
	Net changes in future development costs		7,028				(22,966	)		14,787
	Purchases of minerals in place		163,309				56,069			-
	Revisions of previous quantity estimates		16,283				26,259			(54,775	)
	Accretion of discount		12,536				2,513			6,924
	Changes in timing of estimated cash flows and other		18,353				7,543			(712	)
	End of year	$	255,856			$	125,357		$	25,132
	·	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, is a partnership for federal tax purposes and is not subject to federal income taxes or state or local income taxes that follow the federal treatment, and therefore OVR did not pay or accrue for such taxes. Pursuant to the Exchange OVR’s subsidiaries have become subsidiaries of Earthstone Energy, Inc., which is a taxable entity; as such estimated tax expense was included in the Standardized Measure for December 31, 2014.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation - Additional Information (Details)	0 Months Ended	12 Months Ended
	Dec. 19, 2014	Dec. 31, 2014
	Subsidiary
Oak Valley Resources, LLC [Member]
Organization And Basis Of Presentation [Line Items]
Number of subsidiaries	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]
Common stock shares issued in exchange for acquisition		2,957,000
Percentage of common stock acquired		20.00%
Undivided ownership interest acquired percentage		20.00%
Undivided ownership interest percentage before acquisition		30.00%
Undivided ownership interest percentage after acquisition		50.00%

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Additional Information - (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 21, 2012
	Counterparty								Operator	Operator	Operator	Customer
									Customer	Customer	Customer
									Counterparty
Summary Of Significant Accounting Policies [Line Items]
Revenues									$47,994,000	$29,943,000	$22,295,000
Net income (loss)	-37,318,000	4,215,000	1,529,000	2,740,000	-12,854,000	1,118,000	-4,175,000	-3,964,000	-28,834,000	-19,875,000	-53,321,000
Impairment expense									19,359,000	12,298,000	52,475,000
Number Of Major Customer									1	0	0
Number Of Major Operator									1	2	2
Number of customers accounted for more than 10% of revenue												0
Derivative, number of counterparties	2								2
Liability for Uncertain Tax Positions, Current	0				0				0	0			0
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Customer One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of revenues									60.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Operator One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of revenues									20.00%	47.00%	65.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Operator Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of revenues										11.00%	18.00%
Proved Oil and Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Depletion expenses									18,100,000	16,900,000	12,200,000
Impairment expense									16,900,000	9,800,000	43,900,000
Unproved Oil and Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment expense									2,500,000	2,500,000	8,600,000
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
Oak Valley Energy, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Revenues											4,200,000
Net income (loss)											$2,400,000

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Additional Information (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

17-May-13

Mar. 28, 2013

Apr. 04, 2012

Mar. 08, 2012

Feb. 16, 2012

Feb. 07, 2012

Dec. 19, 2014

Aug. 31, 2013

Jul. 31, 2013

Dec. 18, 2012

Well

Well

Well

Well

Well

acre

acre

Business Acquisition [Line Items]

General and administrative expense

$7,864,000

$7,751,000

$3,280,000

Proceeds from sales of oil and gas properties

488,000

9,976,000

Goodwill

22,992,000

22,992,000

Revenues

47,994,000

29,943,000

22,295,000

Net income (loss)

-37,318,000

4,215,000

1,529,000

2,740,000

-12,854,000

1,118,000

-4,175,000

-3,964,000

-28,834,000

-19,875,000

-53,321,000

Repayment of credit facility

10,825,000

5,192,000

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

9

Effective date of sale

1-Apr-13

Harrison County, Texas [Member]

Business Acquisition [Line Items]

Cash consideration

100

Gain (loss) on sale of properties

-100,000

Number of oil wells sold

1

Effective date of sale

1-Apr-13

Caddo and DeSoto Parishes [Member]

Business Acquisition [Line Items]

Cash consideration

1,600,000

Effective date of acquisition

1-Jan-12

Number of wells acquired

19

Lincoln and Webster Parishes Louisiana [Member]

Business Acquisition [Line Items]

Cash consideration

100,000

Gain (loss) on sale of properties

100,000

Number of oil wells sold

2

Effective date of sale

1-Jan-12

DeSoto Parish, Louisiana [Member]

Business Acquisition [Line Items]

Cash consideration

1,100,000

Gain (loss) on sale of properties

600,000

Number of oil wells sold

6

Number of wells exchange on sale

1

Effective date of exchange

1-Jan-12

Cadeville Prospect [Member]

Business Acquisition [Line Items]

Cash consideration

400,000

Gain (loss) on sale of properties

100,000

Effective date of sale

1-Feb-12

Number of wells exchange on sale

1

Acres of unproved leasehold sold

395

NW Caldwell Prospect [Member]

Business Acquisition [Line Items]

Cash consideration

1,000,000

Effective date of acquisition

25-Jan-12

Effective date of sale

17-May-13

Land subject to ground leases

1,973

2014 Eagle Ford Properties [Member]

Business Acquisition [Line Items]

Total consideration

56,425,000

Common stock shares issued in exchange for acquisition

2,960,000

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

28.57%

Assumed income tax rate

35.00%

Proceeds from sales of oil and gas properties

600,000

Operating expenses

100,000

Goodwill

4,046,000

4,046,000

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

Business Acquisition [Line Items]

General and administrative expense

3,300,000

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

Business Acquisition [Line Items]

General and administrative expense

200,000

2013 Eagle Ford Acquisition [Member]

Business Acquisition [Line Items]

Total consideration

86,687,000

Assumed income tax rate

35.00%

Purchase price, total

15,100,000

71,600,000

Goodwill

0

0

Effective date of acquisition

1-Jan-13

Revenues

9,500,000

Net income (loss)

6,200,000

Acquisition cost

1,100,000

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

Business Acquisition [Line Items]

General and administrative expense

1,100,000

Earthstone Energy Reverse Acquisition [Member]

Business Acquisition [Line Items]

Total consideration

130,000,000

Cash consideration

107,000,000

Common stock shares issued in exchange for acquisition

9,100,000

Common stock, price per share

0.001

Goodwill

18,946,000

18,946,000

Legacy Earthstone

Business Acquisition [Line Items]

Proceeds from sales of oil and gas properties

500,000

Operating expenses

300,000

Legacy Earthstone | Non-recurring Transaction Costs [Member]

Business Acquisition [Line Items]

General and administrative expense

900,000

Assigned Subsidiary [Member]

Business Acquisition [Line Items]

Gain (loss) on sale of properties

4,100,000

Cash consideration by sale of subsidiary

8,500,000

Repayment of credit facility

$5,200,000

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 19, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Total shares of Common Stock outstanding following the Exchange	13,835,128		0
Common stock, shares issued	13,835,128		0
Estimated Fair Value of Assets Acquired:
Goodwill	$22,992,000
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Common stock, shares issued	2,957,288
Closing price of Common Stock	$19.08
Estimated Fair Value of Liabilities Assumed:
Deferred tax liability	4,046,000
Asset retirement obligation	173,000
Amount attributable to liabilities assumed	4,219,000
Total purchase price plus liabilities assumed	60,644,000
Estimated Fair Value of Assets Acquired:
Amount attributable to assets acquired	56,598,000
Goodwill	4,046,000
Total purchase price	56,425,000
Proved Oil and Gas Properties [Member] | 2014 Eagle Ford Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	34,745,000
Unproved Oil and Gas Properties [Member] | 2014 Eagle Ford Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	21,853,000
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
Common stock, shares issued	1,753,388
Closing price of Common Stock	$19.08
Total purchase price	33,455,000
Estimated Fair Value of Liabilities Assumed:
Current liabilities	7,852,000
Long-term debt	7,000,000
Deferred tax liability	2,880,000
Asset retirement obligation	2,227,000
Amount attributable to liabilities assumed	19,959,000
Total purchase price plus liabilities assumed	53,414,000
Estimated Fair Value of Assets Acquired:
Cash	2,920,000
Other current assets	3,466,000
Other non-current assets	745,000
Amount attributable to assets acquired	34,468,000
Goodwill	18,946,000
Total purchase price		130,000,000
Earthstone Energy Reverse Acquisition [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	21,813,000
Earthstone Energy Reverse Acquisition [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	$5,524,000

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Parenthetical ) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Business Acquisition [Line Items]
Exchange tax rate	34.00%
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Exchange tax rate	34.00%
Weighted average commodity prices of oil	56.36
Weighted average commodity prices of natural gas	3.36
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Exchange tax rate	35.00%
Business combination assets acquired notes payable and accrued interest	7,100,000
Cash	2,920,000
Weighted average commodity prices of oil	51.62
Weighted average commodity prices of natural gas	4.58

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures - Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Revenue	$85,633	$66,450
Income (loss) 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]
Revenue		48,291	39,804
Income (loss) before taxes		-5,240	-39,796
Net income available to Earthstone common stockholders		($3,406)	($25,867)
Pro forma net loss per common share:
Basic and diluted		($0.37)	($2.83)

Acquisitions_and_Divestitures_5

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire and Amounts of Assets Acquired and Liabilities Assumed (Details) (2013 Eagle Ford Acquisition [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
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_Divestitures_6

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, 2014
2013 Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Weighted average commodity prices of oil	99.32
Weighted average commodity prices of natural gas	3.24

Derivative_Financial_Instrumen2

Derivative Financial Instruments - Schedule of Open Crude Oil and Natural Gas Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2014
	MMBTU
January 2015 - March 2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Instrument	Swap
Volume in MMBtu	150,000
Fixed Price, MMBtu	4.175
January 2015 - March 2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Instrument	Swap
Volume in MMBtu	75,000
Fixed Price, MMBtu	4.3
January 2015 - June 2015 [Member] | Crude Oil [Member]
Derivative [Line Items]
Instrument	Swap
Volume in Bbls	21,000
Fixed Price, Bbls	91.5
January 2015 - December 2015 [Member] | Crude Oil [Member]
Derivative [Line Items]
Instrument	Swap
Volume in Bbls	66,000
Fixed Price, Bbls	95.1

Derivative_Instruments_Additio

Derivative Instruments - Additional Information (Details) (April 2015 - March 2016 [Member], Crude Oil [Member])	1 Months Ended
	Mar. 31, 2015
	bbl
April 2015 - March 2016 [Member] | Crude Oil [Member]
Disclosure - Derivative Instruments - Additional Information (Details) [Line Items]
Volume in Bbls	5,000
Fixed Price, Bbls	57

Derivative_Financial_Instrumen3

Derivative Financial Instruments - Schedule of Location and Fair Value Amounts of All Derivative Instruments (Details) (Derivatives Not Designated as Hedging Contracts [Member], Commodity Contracts [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Derivative Assets [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Assets	$3,569	$154
Net Recognized Assets	3,569	154
Current Derivative Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Liabilities		-172
Net Recognized Liabilities		-172
Noncurrent Derivative Liabilities [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Liabilities		-28
Net Recognized Liabilities		($28)

Derivative_Financial_Instrumen4

Derivative Financial Instruments - Summary of Gross and Net Information About Commodity Derivative Instruments (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments Gain Loss [Line Items]
Net gain on derivative contracts	$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	3,614	-45
Realized gain on commodity contracts	$778	$341

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value assets transfer from Level 1 to Level 2	$0
Fair value assets transfer from Level 2 to Level 1	0
Fair value liabilities transfer from Level 1 to Level 2	0
Fair value liabilities transfer from Level 2 to Level 1	0
Level 3 [Member] | Fair Value on a Nonrecurring Basis [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments on proved properties	16,900,000	9,800,000	43,900,000
Asset impairments on unproved properties	$2,500,000	$2,500,000	$8,600,000

Fair_Value_Measurements_Summar

Fair Value Measurements - Summary of Fair Value of Financial Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Financial assets
Current derivative assets	$3,569	$154
Financial liabilities
Current derivative liabilities		172
Noncurrent derivative liabilities		28
Fair Value on a Recurring Basis [Member]
Financial assets
Current derivative assets	3,569	154
Total financial assets	3,569	154
Financial liabilities
Current derivative liabilities		172
Noncurrent derivative liabilities		28
Total financial liabilities		200
Fair Value on a Recurring Basis [Member] | Level 2 [Member]
Financial assets
Current derivative assets	3,569	154
Total financial assets	3,569	154
Financial liabilities
Current derivative liabilities		172
Noncurrent derivative liabilities		28
Total financial liabilities		$200

Equity_Additional_Information_

Equity - Additional Information (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 19, 2014	Jan. 31, 2013	31-May-13	Jun. 30, 2013	Dec. 21, 2012	Apr. 25, 2013
Capital Unit [Line Items]
Outstanding common stock equivalents	0	0	0
Common stock, par value	$0.00	$0.00
Oak Valley Resources, LLC [Member]
Capital Unit [Line Items]
Cash investments received	$32,995,000
Percentage of common stock acquired	66.00%			84.00%
Oak Valley Resources, LLC [Member] | Common Stock [Member]
Capital Unit [Line Items]
Cash investments received	2,000
Reverse acquisition, shares	1,753,388			9,124,452
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					16,800,000
Second Capital Call [Member]
Capital Unit [Line Items]
Cash investments received						23,700,000
Third Capital Call [Member]
Capital Unit [Line Items]
Cash investments received	107,000,000						67,000,000
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								150,000,000
Oak Valley Management Limited Liability Company
Capital Unit [Line Items]
Aggregate capital commitments		1,700,000
Oak Valley Management Limited Liability Company | Private Placement [Member]
Capital Unit [Line Items]
Aggregate capital commitments									$62,800,000

Equity_Reconciliation_of_Net_I

Equity - Reconciliation of Net Income and Weighted-Average Common Shares Outstanding for Calculating Basic and Diluted Loss Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]
Net loss	($37,318)	$4,215	$1,529	$2,740	($12,854)	$1,118	($4,175)	($3,964)	($28,834)	($19,875)	($53,321)
Weighted average common shares outstanding:
Basic									9,279,324	9,124,452	9,124,452
Diluted									9,279,324	9,124,452	9,124,452
Net loss per share:
Basic	($3.83)	$0.46	$0.17	$0.30	($1.41)	$0.12	($0.46)	($0.43)	($3.11)	($2.18)	($5.84)
Diluted	($3.83)	$0.46	$0.17	$0.30	($1.41)	$0.12	($0.46)	($0.43)	($3.11)	($2.18)	($5.84)

Stock_Based_Compensation_Addit

Stock Based Compensation - Additional Information (Details) (2014 Long Term Incentive Plan [Member], USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Maximum number of shares available to issue	750,000
Maximum aggregate amount payable to pursue awards	$2
Number of shares issued during period	0
Number of shares remained available for grant	750,000
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
Number of shares of common stock grants to eligible employees	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
Number of shares of common stock grants to eligible employees	150,000

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 19, 2014
Debt Instrument [Line Items]
Credit facility interest rate description	Outstanding borrowings under the OVR Credit Facility and the OVE Credit Facility had annual interest rates at either (a) the London Interbank Offered Rate (bLIBORb) plus the applicable utilization margin of 2.25% to 4.25% (2.42% and 2.96% at December 31, 2013 and 2012, respectively) or (b) the base rate plus the applicable utilization margin of 1.00% to 3.00% (4.25% and 4.75% at December 31, 2013 and 2012, respectively). The commitment rate was 0.500% on all unused borrowings.
Commitment fee percentage	0.50%
Long term debt	$11,200,000
Long-term debt, percentage bearing interest rate	1.66%
Letters of credit outstanding amount	300,000
Borrowing base available under credit facility	68,500,000
Amortization of deferred financing costs	164,000	103,000	48,000
Debt issuance costs	1,000,000	500,000
LIBOR Adjusted Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage		2.42%	2.96%
LIBOR Adjusted Rate [Member] | Minimum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	2.25%
LIBOR Adjusted Rate [Member] | Maximum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	4.25%
Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage		4.25%	4.75%
Base Rate [Member] | Minimum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	1.00%
Base Rate [Member] | Maximum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	3.00%
Four Year Senior Secured Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				500,000,000
Line of credit, maturity period				4 years
Initial borrowing of the credit facility	$80,000,000
Debt outstanding maturity	19-Dec-18
Four Year Senior Secured Revolving Credit Facility | Minimum {Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.38%
Four Year Senior Secured Revolving Credit Facility | Maximum {Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Four Year Senior Secured Revolving Credit Facility | LIBOR Adjusted Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage	1.66%
Four Year Senior Secured Revolving Credit Facility | LIBOR Adjusted Rate [Member] | Minimum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	1.50%
Four Year Senior Secured Revolving Credit Facility | LIBOR Adjusted Rate [Member] | Maximum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	2.50%
Four Year Senior Secured Revolving Credit Facility | Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage	3.75%
Four Year Senior Secured Revolving Credit Facility | Base Rate [Member] | Minimum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	0.50%
Four Year Senior Secured Revolving Credit Facility | Base Rate [Member] | Maximum {Member]
Debt Instrument [Line Items]
Applicable margin percentage	1.50%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility, covenant terms	All of the credit facilities discussed herein contain a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Companybs 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 current ratio 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.
Revolving Credit Facility [Member] | Minimum {Member]
Debt Instrument [Line Items]
Line of credit facility covenant, current ratio	1.00%
Revolving Credit Facility [Member] | Maximum {Member]
Debt Instrument [Line Items]
Line of credit facility covenant, leverage ratio	4.00%

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Summary of Asset Retirement Obligation Transactions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Beginning asset retirement obligations	$3,011	$3,938
Acquisitions	2,742	609
Liabilities incurred	64	316
Accretion expense	317	217	179
Disposal of properties	-56	-110
Revision of estimates		-1,959
Ending asset retirement obligations	$6,078	$3,011	$3,938

Asset_Retirement_Obligations_A

Asset Retirement Obligations - Additional Information (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, current	$408	$70

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Accounts payable, related parties	$2,300,000	$600,000
Oak Valley Management Limited Liability Company
Related Party Transaction [Line Items]
General and administrative expenses related to services	3,900,000	2,200,000	300,000
Accrued expenses, related parties	0	700,000
Related party asset	$0

Commitment_and_Contingencies_D

Commitment and Contingencies (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Operating Leased Assets [Line Items]
2015	$11,040
2016	11,131
2017	2,252
2018	2,262
2019	2,218
Thereafter	2,327
Drilling Contracts [Member]
Operating Leased Assets [Line Items]
2015	8,682
2016	8,845
Gas Contract [Member]
Operating Leased Assets [Line Items]
2015	1,643
2016	1,647
2017	1,643
2018	1,643
2019	1,643
Thereafter	2,327
Office Leases [Member]
Operating Leased Assets [Line Items]
2015	715
2016	639
2017	609
2018	619
2019	$575

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 28, 2015	Jan. 31, 2015
				DrillingRigs	DrillingRigs
Loss Contingencies [Line Items]
Rent expense	$400,000	$100,000	$100,000
Minimum future lease commitments for non-cancelable leases	3,200,000
Gas Purchase and Gas Processing Contract
Loss Contingencies [Line Items]
Pipeline fee	0.45
Holding pipeline capacity for Company's use	10,000
Purchasing and processing contract expiry date	1-Jun-21
Drilling Commitments
Loss Contingencies [Line Items]
Daily drilling rate of wells	29,000
Number of drilling rigs under contract	3
Contractual obligations, liquidated damages	10,900,000
Minimum commitment per terms of the agreement	$16,000,000
Drilling Rigs Contract Period	18 months
Subsequent Event [Member] | Drilling Commitments
Loss Contingencies [Line Items]
Number of drilling rigs concluded				1	1

Income_Taxes_Components_of_Inc

Income Taxes - Components of Income Tax Provision (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014
Deferred:
Federal		$21,803
State		302
Total deferred		22,105
Total income tax provision	$22,105	$22,105

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Statutory income tax rate	34.00%
Deferred income tax arising from change in tax status of Oak Valley	$28,347,000
Statutory depletion carry-forward	6,300,000
Tax credit carryforward annual limitations on use	$1,000,000

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Taxes Computed at Corporate Federal Statutory Income Tax Rate (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Non-taxable Oak Valley income prior to merger		($4,142)
Deferred income tax arising from change in tax status of Oak Valley		28,347
State income taxes, net of Federal benefit		188
Total income tax provision	$22,105	$22,105
Effective tax rate		-329.00%

Income_Taxes_Components_of_Def

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
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	-381
Oil & gas properties	-29,730
Asset retirement obligation	1,952
Intangible assets	130
Net deferred noncurrent tax assets (liabilities)	-29,258
Net deferred tax liability	($29,032)

Supplemental_Selected_Quarterl2

Supplemental Selected Quarterly Financial Data (Unaudited) - Schedule of Supplemental Selected Quarterly Financial Data (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Oil and gas revenues	$12,018	$11,957	$12,059	$11,577	$9,107	$11,208	$6,209	$3,110	$47,611	$29,634	$17,091
Other revenues	90	98	86	109	17	96	80	116
Operating expenses	31,407	10,204	9,192	7,777	21,803	10,095	10,696	7,049	58,580	49,643	75,392
Income (loss) from operations	-19,299	1,851	2,953	3,909	-12,679	1,209	-4,407	-3,823	-10,586	-19,700	-53,097
Other income (expense), net	4,086	2,364	-1,424	-1,169	-175	-91	232	-141	62	16	49
Income tax expense	-22,105								-22,105
Net income (loss)	($37,318)	$4,215	$1,529	$2,740	($12,854)	$1,118	($4,175)	($3,964)	($28,834)	($19,875)	($53,321)
Basic net income (loss) per share	($3.83)	$0.46	$0.17	$0.30	($1.41)	$0.12	($0.46)	($0.43)	($3.11)	($2.18)	($5.84)
Diluted net income ( loss) per share	($3.83)	$0.46	$0.17	$0.30	($1.41)	$0.12	($0.46)	($0.43)	($3.11)	($2.18)	($5.84)

Supplemental_Information_On_Oi2

Supplemental Information On Oil And Gas Exploration And Production Activities - Costs Incurred Related to Oil and Gas Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Acquisition cost:
Proved	$74,728	$51,488	$1,609
Unproved	36,236	32,863	11,589
Exploration costs:
Exploratory drilling		64	2,013
Geological and geophysical	111	394
Development costs	75,105	32,511	24,222
Total additions	$186,180	$117,320	$39,433

Supplemental_Information_On_Oi3

Supplemental Information On Oil And Gas Exploration And Production Activities - Costs Incurred Related to Oil and Gas Activities (Parenthetical) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Proved	$74,728	$51,488	$1,609
Unproved	36,236	32,863	11,589
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_Oi4

Supplemental Information On Oil And Gas Exploration And Production Activities - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBoe	MBoe	MBoe
Reserve Quantities [Line Items]
Additions to oil and gas properties	$186,180	$117,320	$39,433
Unweighted average of first of the month prices of natural gas	4.309	3.666
Unweighted average of first of the month prices of oil	94.99	96.94
Proved developed and undeveloped reserves increase	10,800,000	8,800,000
Proved developed reserves increase	6,100,000	1,800,000
Proved undeveloped reserves increase	4,700,000	7,000,000
Extensions and discoveries	2,364	4,812	1,306
Purchases of minerals in place	8,473	2,382
Proved developed and undeveloped reserves increase	10,800,000	8,800,000
Working interest percentage		30.00%
Proved developed and undeveloped reserves decrease			8,000,000
Proved developed reserves decrease			1,600,000
Proved undeveloped reserves decrease			6,400,000
Sale of minerals in place		-15	-329
Revision to previous estimates	806	2,395	-8,426
Proved undeveloped reserves	12,392	7,725	656
Estimated proved undeveloped reserves increase	4,700,000
Proved undeveloped reserve transferred percentage	63.00%
Purchases	4,451
Revisions	672
Proved undeveloped reserves increases due to change in prices	1,014
Oak Valley Resources L L C Exchange Agreement
Reserve Quantities [Line Items]
Extensions and discoveries	2,364
Purchases	4,500,000
Eagle Ford Property
Reserve Quantities [Line Items]
Purchases of minerals in place	8,473
Henry Hub Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas	4.309	3.666	2.752
West Texas Intermediate Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil	94.99	96.94	94.71
New Wells
Reserve Quantities [Line Items]
Additions to oil and gas properties	$200	$1,000	$100

Supplemental_Information_On_Oi5

Supplemental Information On Oil And Gas Exploration And Production Activities - Net Changes in Capitalized Exploratory Well Costs (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Extractive Industries [Abstract]
Balance, beginning of year	$2,032	$19	$0
Additions to capitalized exploratory well costs pending the determination of proved reserves	64	2,013
Capitalized exploratory well costs charged to expense	-2,096
Balance, end of year	$0	$2,032	$0

Supplemental_Information_On_Oi6

Supplemental Information On Oil And Gas Exploration And Production Activities - Changes in Quantities of Proved Oil and natural Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBoe	MBoe	MBoe
Reserve Quantities [Line Items]
Beginning balance	11,431	2,594	10,592
Extensions and discoveries	2,364	4,812	1,306
Sale of minerals in place		-15	-329
Purchases of minerals in place	8,473	2,382
Production	-882	-737	-549
Revision to previous estimates	806	2,395	-8,426
Ending Balance	22,192	11,431	2,594
Proved developed reserves	9,800	3,706	1,938
Proved undeveloped reserves	12,392	7,725	656
Crude Oil [Member]
Reserve Quantities [Line Items]
Beginning balance	6,078,000	519,000	1,182,000
Extensions and discoveries	1,909,000	3,586,000	407,000
Sale of minerals in place		-15,000	-301,000
Purchases of minerals in place	7,025,000	2,051,000
Production	-403,000	-163,000	-90,000
Revision to previous estimates	-806,000	100,000	-679,000
Ending Balance	13,803,000	6,078,000	519,000
Proved developed reserves	6,093,000	1,307,000	296,000
Proved undeveloped reserves	7,710,000	4,771,000	223,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance	24,213	10,099	56,459
Extensions and discoveries	1,403	4,198	3,596
Sale of minerals in place			-165
Purchases of minerals in place	6,064	709
Production	-2,132	-2,635	-2,298
Revision to previous estimates	9,031	11,842	-47,493
Ending Balance	38,579	24,213	10,099
Proved developed reserves	16,214	11,053	8,245
Proved undeveloped reserves	22,365	13,160	1,854
Natural Gas Liquids
Reserve Quantities [Line Items]
Beginning balance	1,318,000	392,000
Extensions and discoveries	221,000	526,000	299,000
Purchases of minerals in place	437,000	213,000
Production	-124,000	-134,000	-76,000
Revision to previous estimates	107,000	321,000	169,000
Ending Balance	1,959,000	1,318,000	392,000
Proved developed reserves	1,005,000	557,000	268,000
Proved undeveloped reserves	954,000	761,000	124,000

Supplemental_Information_On_Oi7

Supplemental Information On Oil And Gas Exploration And Production Activities - Schedule of Changes in Proved Undeveloped Reserves (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012
	MBoe	MBoe
Extractive Industries [Abstract]
Beginning Balance	7,725	656
Undeveloped reserves transfer to developed	-1,306
Revisions	672
Purchases	4,451
Extensions and discoveries	850
Ending balance	12,392	656

Supplemental_Information_On_Oi8

Supplemental Information On Oil And Gas Exploration And Production Activities - Schedule Of Standardized Measure (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Extractive Industries [Abstract]
Future cash inflows	$1,464,138	$718,049	$88,234
Future production costs	-427,113	-202,957	-32,967
Future development costs	-312,010	-220,828	-15,271
Future income tax expense	-180,248
Future net cash flows	544,767	294,264	39,996
10% annual discount for estimated timing of cash flows	-288,911	-168,907	-14,864
Standardized measure of discounted future cash flows	$255,856	$125,357	$25,132	$69,240

Supplemental_Information_On_Oi9

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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Standardized Measure, beginning of year	$125,357	$25,132	$69,240
Sales of oil and gas produced, net of production costs	-35,794	-20,287	-10,300
Sales of minerals in place		-380	-10,274
Net changes in prices and production costs	-34,681	241	-6,133
Extensions, discoveries, and improved recoveries	54,157	48,006	16,375
Changes in income taxes, net (1)	-88,944
Previously estimated development costs incurred during the period	18,252	3,227
Net changes in future development costs	7,028	-22,966	14,787
Purchases of minerals in place	163,309	56,069
Revisions of previous quantity estimates	16,283	26,259	-54,775
Accretion of discount	12,536	2,513	6,924
Changes in timing of estimated cash flows and other	18,353	7,543	-712
Standardized Measure, end of year	$255,856	$125,357	$25,132