Earthstone Energy (ESTE) 10-K 15 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 09, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Trading Symbol	ESTE
Entity Registrant Name	EARTHSTONE ENERGY INC
Entity Central Index Key	10,254
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		22,273,820
Entity Public Float			$ 133,417,225

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash	$ 10,200	$ 23,264
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	13,998	13,529
Joint interest billings and other, net of allowance of $163 and $170 at December 31, 2016 and 2015, respectively	2,698	4,924
Derivative asset		3,694
Prepaid expenses and other current assets	446	498
Total current assets	27,342	45,909
Oil and gas properties, successful efforts method:
Proved properties	363,072	283,644
Unproved properties	51,723	34,609
Total oil and gas properties	414,795	318,253
Accumulated depreciation, depletion and amortization	(145,393)	(119,920)
Net oil and gas properties	269,402	198,333
Other noncurrent assets:
Goodwill	17,620	17,532
Office and other equipment, net of accumulated depreciation of $1,600 and $1,028 at December 31, 2016 and 2015, respectively	1,479	1,934
Other noncurrent assets	669	1,236
TOTAL ASSETS	316,512	264,944
Current liabilities:
Accounts payable	11,927	11,580
Revenues and royalties payable	10,769	8,576
Accrued expenses	5,392	12,975
Derivative liability	4,595
Advances	4,542	15,447
Current portion of long-term debt	1,604
Total current liabilities	38,829	48,578
Noncurrent liabilities:
Long-term debt	12,693	11,191
Asset retirement obligation	6,013	5,075
Derivative liability	1,575
Deferred tax liability	15,776
Other noncurrent liabilities	169	227
Total noncurrent liabilities	36,226	16,493
Commitments and Contingencies (Note 14)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding
Common stock, $0.001 par value, 100,000,000 shares authorized; 22,289,177 issued and 22,273,820 outstanding at December 31, 2016 and 13,835,128 issued and 13,819,771 outstanding at December 31, 2015	23	14
Additional paid-in capital	454,202	358,086
Accumulated deficit	(212,308)	(157,767)
Treasury stock, 15,357 shares at December 31, 2016 and 2015, respectively	(460)	(460)
Total equity	241,457	199,873
TOTAL LIABILITIES AND EQUITY	$ 316,512	$ 264,944

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Joint interest billings and other, allowance	$ 163	$ 170
Office and other equipment, accumulated depreciation	$ 1,600	$ 1,028
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	22,289,177	13,835,128
Common stock, shares outstanding	22,273,820	13,819,771
Treasury stock, shares	15,357	15,357

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES
Oil	$ 34,358,000	$ 39,849,000	$ 34,734,000
Natural gas	5,046,000	5,457,000	9,367,000
Natural gas liquids	2,865,000	2,158,000	3,510,000
Total revenues	42,269,000	47,464,000	47,611,000
OPERATING COSTS AND EXPENSES
Lease operating expense	13,415,000	14,550,000	9,422,000
Severance taxes	2,198,000	2,582,000	2,002,000
Rig idle and contract termination expense	5,059,000
Re-engineering and workovers	1,652,000	872,000	708,000
Impairment expense	24,283,000	138,086,000	19,359,000
Depreciation, depletion and amortization	25,937,000	31,228,000	18,414,000
General and administrative expense	9,414,000	9,711,000	6,830,000
Stock-based compensation	3,301,000
Transaction costs	2,483,000	589,000	1,034,000
Accretion of asset retirement obligation	551,000	550,000	317,000
Exploration expense	5,000	142,000	111,000
Total operating costs and expenses	88,298,000	198,310,000	58,197,000
Gain on sale of oil and gas properties	8,000	1,617,000
Loss from operations	(46,021,000)	(149,229,000)	(10,586,000)
OTHER INCOME (EXPENSE)
Interest expense, net	(1,282,000)	(722,000)	(597,000)
(Loss) gain on derivative contracts, net	(6,638,000)	6,431,000	4,392,000
Other (expense) income, net	(72,000)	423,000	62,000
Total other income (expense)	(7,992,000)	6,132,000	3,857,000
Loss before income taxes	(54,013,000)	(143,097,000)	(6,729,000)
Income tax expense (benefit)	528,000	(26,442,000)	22,105,000
Net loss	$ (54,541,000)	$ (116,655,000)	$ (28,834,000)
Net loss per common share:
Basic	$ (2.92)	$ (8.43)	$ (3.11)
Diluted	$ (2.92)	$ (8.43)	$ (3.11)
Weighted average common shares outstanding:
Basic	18,651,582	13,835,128	9,279,324
Diluted	18,651,582	13,835,128	9,279,324

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Oak Valley Resources, LLC [Member]	Eagle Ford [Member]	Lynden Arrangement [Member]	Members' Equity [Member]	Members' Equity [Member]Oak Valley Resources, LLC [Member]	Members' Equity [Member]Oak Valley Resources, LLC [Member]Subsidiaries [Member]	Common Stock [Member]	Common Stock [Member]Oak Valley Resources, LLC [Member]	Common Stock [Member]Oak Valley Resources, LLC [Member]Subsidiaries [Member]	Common Stock [Member]Eagle Ford [Member]	Common Stock [Member]Lynden Arrangement [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]Oak Valley Resources, LLC [Member]	Additional Paid-in Capital [Member]Oak Valley Resources, LLC [Member]Subsidiaries [Member]	Additional Paid-in Capital [Member]Eagle Ford [Member]	Additional Paid-in Capital [Member]Lynden Arrangement [Member]	Accumulated Deficit [Member]	Treasury Stock [Member]	Treasury Stock [Member]Oak Valley Resources, LLC [Member]
Beginning Balance, amount at Dec. 31, 2013	$ 148,922				$ 148,922
Common stock issued, net of offering costs and contributions		$ 107,020				$ 107,020	$ (268,220)			$ 9					$ 268,211
Common stock issued, net of offering costs and contributions, shares										9,124,452
Stock issued during period for acquisitions and reverse acquisition		$ 32,995	$ 56,425						$ 2		$ 3			$ 33,453		$ 56,422				$ (460)
Stock issued during period for acquisitions and reverse acquisition, shares									1,753,388		2,957,288									(15,357)
Net loss	(28,834)				$ 12,278													$ (41,112)
Ending Balance, amount at Dec. 31, 2014	316,528							$ 14					$ 358,086					(41,112)	$ (460)
Ending Balance, shares at Dec. 31, 2014								13,835,128											(15,357)
Net loss	(116,655)																	(116,655)
Ending Balance, amount at Dec. 31, 2015	199,873							$ 14					358,086					(157,767)	$ (460)
Ending Balance, shares at Dec. 31, 2015								13,835,128											(15,357)
Common stock issued, net of offering costs and contributions	47,125							$ 5					47,120
Common stock issued, net of offering costs and contributions, shares								4,753,770
Stock-based compensation expense	3,301												3,301
Stock issued during period for acquisitions and reverse acquisition				$ 45,699								$ 4					$ 45,695
Stock issued during period for acquisitions and reverse acquisition, shares												3,700,279
Net loss	(54,541)																	(54,541)
Ending Balance, amount at Dec. 31, 2016	$ 241,457							$ 23					$ 454,202					$ (212,308)	$ (460)
Ending Balance, shares at Dec. 31, 2016								22,289,177											(15,357)

Consolidated Statements of Equ6

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

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net loss	$ (54,541,000)	$ (116,655,000)	$ (28,834,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	25,937,000	31,228,000	18,414,000
Impairment of goodwill	17,532,000	1,547,000	0
Impairment of proved and unproved oil and gas properties	24,283,000	138,086,000	19,359,000
Total loss (gain) on derivative contracts, net	6,638,000	(6,431,000)	(4,392,000)
Operating portion of net cash received in settlement of derivative contracts	3,225,000	6,306,000	778,000
Rig idle and termination expense	5,059,000
Stock-based compensation	3,301,000
Accretion of asset retirement obligations	551,000	550,000	317,000
Deferred income taxes	528,000	(26,533,000)	22,105,000
Amortization of deferred financing costs	298,000	264,000	164,000
Settlement of asset retirement obligations	(15,000)	(108,000)	(56,000)
Gain on sale of oil and gas properties	(8,000)	(1,617,000)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	3,807,000	9,246,000	(5,305,000)
Decrease (increase) in prepaid expenses and other current assets	511,000	779,000	(194,000)
(Decrease) increase in accounts payable and accrued expenses	(9,151,000)	(30,887,000)	28,408,000
Increase (decrease) in revenues and royalties payable	2,194,000	(8,739,000)	7,099,000
(Decrease) increase in advances	(10,905,000)	(5,929,000)	17,925,000
Net cash provided by (used in) operating activities	1,712,000	(10,440,000)	75,788,000
Cash flows from investing activities:
Acquisition of oil and gas properties		(8,706,000)	(18,772,000)
Additions to oil and gas properties	(28,417,000)	(61,060,000)	(83,041,000)
Additions to office and other equipment	(117,000)	(378,000)	(1,385,000)
Proceeds from sale of oil and gas properties		3,441,000
Proceeds from sale of land		101,000
Net cash used in investing activities	(59,868,000)	(66,602,000)	(107,437,000)
Cash flows from financing activities:
Proceeds from borrowings	36,597,000		11,191,000
Repayments of borrowings	(38,549,000)		(10,825,000)
Deferred financing costs	(81,000)	(141,000)	(613,000)
Contributions, net of issuance costs			106,920,000
Issuance of common stock, net of offering costs of $2.7 million	47,125,000
Net cash provided by (used in) financing activities	45,092,000	(141,000)	106,673,000
Net (decrease) increase in cash and cash equivalents	(13,064,000)	(77,183,000)	75,024,000
Cash at beginning of period	23,264,000	100,447,000	25,423,000
Cash at end of period	10,200,000	23,264,000	100,447,000
Cash paid for:
Interest	961,000	415,000	493,000
Non-cash investing and financing activities:
Asset retirement obligations	152,000	150,000	237,000
Accruals of property, plant and equipment	2,374,000	7,665,000	18,219,000
Acquisition of oil and gas properties		1,991,000
Promissory Note	5,059,000
Lynden Arrangement [Member]
Cash flows from investing activities:
Business acquisition, net of cash acquired	(31,334,000)
Non-cash investing and financing activities:
Common stock issued	45,699,000
Oak Valley Resources, LLC [Member]
Cash flows from investing activities:
Business acquisition, net of cash acquired			(4,239,000)
2014 Eagle Ford Acquisition [Member]
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Impairment of goodwill		1,500,000
Non-cash investing and financing activities:
Common stock issued			56,425,000
Proved And Unproved Property [Member]
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Impairment of proved and unproved oil and gas properties	$ 6,751,000	$ 136,539,000	$ 19,359,000

Consolidated Statements of Cas8

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	Jun. 21, 2016	Dec. 31, 2016
Statement Of Cash Flows [Abstract]
Issuance of common stock, offering costs	$ 2.7	$ 2.7

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. – Organization and Basis of Presentation Earthstone Energy, Inc. (together with our consolidated subsidiaries, the “Company,” “our,” “we,” “us,” “Earthstone” or similar terms), a Delaware corporation, is a growth-oriented independent oil and natural gas development and production company. In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities. Our operations are all in the up-stream segment of the oil and natural gas industry and all our properties are onshore in the United States. Oak Valley Resources, LLC (“OVR”) is a Delaware limited liability company formed on December 14, 2012. On December 19, 2014, the Company acquired three operating subsidiaries of OVR, in exchange for shares of Earthstone common stock (the “Exchange”). Prior to the Exchange, OVR was an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas and natural gas liquids (“NGLs”), with properties in Texas, Oklahoma, and Louisiana. OVR was formed through a series of transactions that conveyed properties and committed cash contributions from various investors including EnCap Investments L.P. (“EnCap”), Wells Fargo Central Pacific Holdings, Inc. (“Wells Fargo”), VILLCo Capital II, LLC (“VILLCo”) and an affiliate of OVR, Oak Valley Management, LLC (“OVM”). Certain prior-period amounts have been reclassified to conform to current-period presentation as follows: • Consolidated Statement of Operations – Accretion of asset retirement obligation has been reclassified out of Lease operating expense and included in its own line item in Operating Costs and Expenses. Transaction costs have been reclassified out of General and administrative expense and included in its own line item in Operating Costs and Expenses. Gain on sale of oil and gas properties has be reclassified from within Revenues to its own line item to arrive at Loss from operations. Gathering income has be reclassified from within Revenues to inclusion in Lease operating expense within Operating Costs and Expenses. These reclassifications had no effect on Loss from operations, Loss before income taxes, or Net loss for each of the three years ended December 31, 2016, 2015 and 2014. • Consolidated Statement of Cash Flows – Non-cash changes in fair value of the Company’s commodity swaps have been reclassified from the Unrealized (gain) loss on derivative contracts and bifurcated into Total loss (gain) on derivative contracts, net, and Operating portion of net cash received in settlement of derivative contracts. The reclassification had no effect on Net cash provided by operating activities for each of the three years ended December 31, 2016, 2015 and 2014.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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 (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation. Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods then ended. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of our estimates. All reserve data included in these Consolidated Financial Statements are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered. Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, goodwill, asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) Accounts Receivable Accounts receivable include amounts due from crude oil, natural gas, and natural gas liquids purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and natural gas liquids sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability. Allowance for uncollectible accounts receivable was $0.2 million at December 31, 2016 and 2015. Derivative Instruments The Company utilizes derivative instruments in order to manage exposure to commodity price risk associated with future oil and natural gas production. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are marked-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in (Loss) gain on derivative contracts, net (Loss) gain on derivative contracts, net Oil and Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the successful efforts method of accounting for natural gas properties as proscribed by the SEC. For more information see Note 6. Oil and Natural Gas Properties . Goodwill Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. During the years ended December 31, 2016 and 2015, impairments to Goodwill of $17.5 million and $1.5 million, respectively, were recorded. There were no impairments to Goodwill recorded in the year ended December 31, 2014. For further discussion, see Note 7. Goodwill Segment Reporting The Company’s operations are conducted through two locations which have been deemed operating segments under ASC 280, Segment Reporting. The Company aggregated them into one reporting segment because these operating segments sell the same products, under the same production processes, with the same type of customers, under the same method of distribution, and in the same type of regulatory environment. Asset Retirement Obligations Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For further discussion, see Note 12. Asset Retirement Obligations Business Combinations The Company accounts for the acquisition of oil and gas properties not commonly controlled based on the requirements of FASB ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved developed oil and gas properties as business combinations. Revenue Recognition Oil, natural gas, and natural gas liquids revenues represent income from the production and delivery of oil, natural gas, and natural gas liquids, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has been transferred, and collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. The Company had no significant gas imbalances as of December 31, 2016, 2015, or 2014. Concentration of Credit Risk Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms. The purchasers of the Company’s oil, natural gas, and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2016, two purchasers accounted for 41% and 19%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In 2015 and 2014, one purchaser accounted for 62% and 60% respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2016, 2015, and 2014. Additionally, at December 31, 2016, two purchasers accounted for 28% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. At December 31, 2015, one purchasers accounted for 25% of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2016 and 2015. The Company holds working interests in oil and gas properties for which a third party serves as operator. The operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. The Company recognizes the cash received as revenue. In 2016 and 2015, one operator distributed 19% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids revenues. In 2014, a different operator distributed 20% of the Company’s oil, natural gas and natural gas liquids revenues. The derivative instruments of the Company are with a small number of counterparties and, from time-to-time, may represent material assets in the Consolidated Balance Sheets. At December 31, 2016, the Company had no derivative contracts in asset positions. At December 31, 2015, two counterparties accounted for 69% and 31%, respectively, of the Company’s Current derivative asset in the Consolidated Balance Sheet. The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage. Income Taxes We are a U.S. company operating in multiple states, as well as one foreign legal entity, Lynden Energy Corp., which is a Canadian company discussed in Note 3. Acquisitions and Divestitures Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in our Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2016 and 2015, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets. The historical financials prior to December 19, 2014 are those of OVR. OVR was not subject to taxation and therefore tax provisions were not recorded on the historical consolidated financial statements. As a result of the Exchange Agreement, OVR is now a taxable entity and a charge to earnings to record a tax provision was included in the purchase accounting adjustments. The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2016, 2015 or 2014. Recently Issued Accounting Standards Standards adopted in 2016 Debt Issuance Costs – In April 2015, the Financial Accounting Standards Board (“FASB”) issued updated guidance which changes the presentation of debt issuance costs in the financial statements. Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update was effective for interim and annual periods beginning after December 15, 2015. The Company adopted this standards update, as required, effective January 1, 2016. The adoption of this standards update did not affect the Company’s method of amortizing debt issuance costs and did not have a material impact on its Consolidated Financial Statements. Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination. The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standards update was effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The Company adopted this standard update, as required, effective January 1, 2016, which did not have a material impact on its Consolidated Financial Statements. Stock Compensation - In March 2016, the FASB issued updated guidance on share-based payment accounting. The standards update is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The standards update is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. The Company elected to early-adopt this standards update as of April 1, 2016 in connection with its initial grant of awards under the Company’s 2014 Long Term Incentive Plan. The Company has elected to record the impact of forfeitures on compensation cost as they occur. The Company is also permitted to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory tax rates. There was no retrospective adjustment as the Company did not have any outstanding equity awards prior to adoption. See . Standards not yet adopted Revenue Recognition - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. This update amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of good and services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those good or services. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company does not expect the adoption of this guidance to have a material impact on its Consolidated Financial Statements. Leases – In February 2016, the FASB issued updated guidance on accounting for leases. This update requires lessees to recognize a right of use asset and lease liability on the balance sheet for all leases, with the exception of short-term leases. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company will adopt this standards update, as required, beginning with the first quarter of 2019. The Company is currently evaluating the effect of the update on our consolidated financial statements and related disclosures. Statement of Cash Flows – In August 2016, the FASB issued updated guidance that These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2018. The Company is currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Lynden Arrangement On May 18, 2016, the Company acquired Lynden Energy Corp. (“Lynden”) in an all-stock transaction through an arrangement (the “Lynden Arrangement”) instead of a merger because Lynden is incorporated in British Columbia, Canada. The Company acquired all outstanding shares of Lynden’s common stock, through a newly formed subsidiary, with Lynden surviving as a wholly-owned subsidiary of the Company, issuing 3,700,279 shares of its common stock, $0.001 par value per share (the “Common Stock”), to the holders of the common stock of Lynden. The Lynden Arrangement was accounted for as a business combination in accordance with FASB ASC Topic 805, Business Combinations An allocation of the purchase price was prepared using, among other things, an independent fair market valuation. The following is still preliminary with respect to final tax amounts and includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. We expect the purchase price allocation to be finalized in the first quarter of 2017. Based on our ongoing review of preliminary tax amounts, we adjusted the deferred tax liability recorded as a result of the acquisition and a corresponding change to goodwill in the fourth quarter of 2016. The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed and resulting goodwill ( in thousands, except share and share price amount Consideration: Shares of Earthstone common stock issued in the Arrangement 3,700,279 Closing price of Earthstone common stock as of May 18, 2016 $ 12.35 Total consideration to Lynden shareholders $ 45,698 Fair Value of Liabilities Assumed: Credit facility (4) $ 36,597 Current liabilities 1,915 Deferred tax liability (1) 15,157 Asset retirement obligations 250 Total consideration plus liabilities assumed $ 99,617 Fair Value of Assets Acquired: Cash and cash equivalents (4) $ 5,263 Current assets 2,018 Proved oil and gas properties (2)(3) 48,116 Unproved oil and gas properties 26,600 Amount attributable to assets acquired $ 81,997 Goodwill (5) $ 17,620 (1) This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Lynden Arrangement, tax-effected using a tax rate of approximately 34.5%. (2) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $64.73 per barrel of oil, $3.68 per Mcf of natural gas and $19.34 per barrel of oil equivalent for natural gas liquids, after adjustments for transportation fees and regional price differentials. (3) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projecting of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4. Fair Value Measurements, (4) Concurrent with closing the Lynden Arrangement, the Company paid off the outstanding balance of $36.6 million on the Lynden credit facility. The settlement of the debt and the cash acquired is equal to the $31.3 million net cash outflow associated with the Lynden Arrangement. (5) Goodwill was determined to be the excess consideration exchanged over the fair value of the net assets of Lynden on May 18, 2016. The goodwill resulted from the expected synergies of the management team and balance sheet of the Company combined with the key assets acquired in the Midland Basin area. The goodwill recognized will not be deductible for tax purposes. The following unaudited supplemental pro forma results of operations present consolidated information assuming the Lynden Arrangement had been completed as of January 1, 2014. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for the Company and Lynden and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired, (ii) accretion expense associated with the asset retirement obligations recorded using the Company’s assumptions about the future liabilities and (iii) interest expense based on the combined debt of the Company post-acquisition. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information ( in thousands, except per share amounts Years ended December 31, 2016 2015 2014 (Unaudited) Revenue $ 47,679 $ 62,817 $ 112,370 (Loss) income before taxes $ (53,510 ) $ (148,609 ) $ 32,912 Net (loss) income available to Earthstone common stockholders $ (54,744 ) $ (122,598 ) $ 19,518 Pro Forma net (loss) income per common share: Basic $ (2.73 ) $ (6.99 ) $ 1.11 Diluted $ (2.73 ) $ (6.99 ) $ 1.11 Earthstone Energy Reverse Acquisition On December 19, 2014, the Company acquired three operating subsidiaries of OVR, which included producing assets, undeveloped acreage and cash, in exchange for shares of Common Stock (the “Exchange”), which resulted in a change of control of the Company. Pursuant to the Exchange Agreement, OVR contributed to Earthstone the membership interests of its three subsidiaries, Earthstone Operating, LLC (formerly Oak Valley Operating, LLC (“OVO”)), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”). OVR received approximately 9.124 million shares of the Common Stock of the Company. The Exchange resulted in a change of control of the Company. The Exchange was recorded in accordance with FASB ASC An allocation of the purchase price was prepared using, among other things, the December 31, 2014 reserve report prepared by Cawley, Gillespie and Associates, Inc. (“CG&A”), adjusted by the Company’s reserve engineering staff back to the December 19, 2014 acquisition date. The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets ( in thousands, except share and share price amounts Shares of Common Stock issued as consideration 1,753,388 Closing price of Common Stock as of December 19, 2014 $ 19.08 Total purchase price $ 33,455 Estimated Fair Value of Liabilities Assumed: Current liabilities $ 7,631 Long-term debt 7,000 Deferred tax liability (1) 2,880 Asset retirement obligation 1,035 Amount attributable to liabilities assumed 18,546 Total purchase price plus liabilities assumed $ 52,001 Estimated Fair Value of Assets Acquired: Cash (2) $ 2,920 Other current assets 3,466 Proved oil and natural gas properties (3) (4) 21,813 Unproved oil and natural gas properties 5,524 Other non-current assets 746 Amount attributable to assets acquired $ 34,469 Goodwill (5) $ 17,532 (1) This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Exchange, tax-effected using a tax rate of approximately 35%. (2) Net cash flow related to the Exchange was an outflow of $4.2 million which consisted of the $7.1 million repayment of long-term debt (plus accrued interest) less the cash acquired of $2.9 million. (3) 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. (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 4. Fair Value Measurements (5) Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. In 2016, due to the commodity price environment, the Company determined that the amount recorded was no longer recoverable and recognized a full impairment Note 7.Goodwill 2014 Eagle Ford Acquisition Properties On December 19, 2014, immediately following the Exchange, Flatonia Energy, LLC (“Flatonia”), Parallel Resource Partners, LLC (“Parallel”), and Sabine, closed a contribution agreement (the “Flatonia Contribution Agreement”) by and among the Company, OVR, Sabine, OVO, Parallel, and Flatonia, whereby Parallel contributed 28.57% of the oil and natural gas property interests held by Flatonia, a wholly owned subsidiary of Parallel, in exchange for approximately 2.957 million shares of Common Stock. The assets subject to the Flatonia Contribution Agreement were oil and natural gas property interests in producing wells and acreage in the Eagle Ford trend of Texas (the “2014 Eagle Ford Acquisition Propertie s . An allocation of the purchase price was prepared using, the December 31, 2014 reserve report prepared by CG&A that was adjusted by the Company’s reserve engineering staff back to December 19, 2014. 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 2,957,288 Closing price of Common Stock as of December 19, 2014 $ 19.08 Total purchase price $ 56,425 Estimated Fair Value of Liabilities Assumed: Deferred tax liability (1) $ 1,547 Asset retirement obligation 173 Amount attributable to liabilities assumed 1,720 Total purchase price plus liabilities assumed $ 58,145 Estimated Fair Value of Assets Acquired: Proved oil and natural gas properties (2) (3) $ 34,745 Unproved oil and natural gas properties 21,853 Amount attributable to assets acquired $ 56,598 Goodwill (4) $ 1,547 (1) This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Flatonia Contribution Agreement, tax-effected using a tax rate of approximately 34%. (2) 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. (3) 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 4. Fair Value Measurements (4) Goodwill was determined as the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. In 2015, due to the commodity price environment, the Company determined that the goodwill balance was not recoverable and therefore fully impaired it, recording a goodwill impairment charge Note 7.Goodwill Other Acquisitions In June 2015, the Company acquired a 50% operated working interests in approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production by two gross Austin Chalk wells with gross production of 44 barrels of oil equivalent per day as of the time of acquisition. Also during June 2015, the Company acquired 400 gross acres in northern Karnes County, Texas, which is adjacent to the 1,000 gross acres in southern Gonzales County, Texas. Subsequent trades in Karnes County reduced the gross acreage from 400 to 350 gross acres (117 net acres). The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands) Purchase price $ 4,066 Estimated fair value of assets acquired: Proved oil and natural gas properties $ 588 Unproved oil and natural gas properties 3,496 Total assets acquired $ 4,084 Estimated fair value of liabilities assumed: Asset retirement obligations $ 13 Other liabilities 5 Total liabilities assumed $ 18 Consideration paid $ 4,066 Additionally, in June 2015, the Company acquired additional acreage and working interest in wells located within existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.0 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells. The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that were in the drilling and completion phase. In August 2015, the Company acquired a 33% working interest in approximately 1,650 gross acres, in southern Gonzales County, Texas for $3.3 million. Divestitures In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes, Louisiana, for cash consideration of $3.4 million. The Company recorded a gain of $1.6 million on the sale. The effective date of the transaction was March 1, 2015.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 4. Fair Value Measurements FASB ASC Topic 820, The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC 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, 2016. Fair Value on a Recurring Basis Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The swaps are also designated as Level 2 within the valuation hierarchy. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the consolidated financial statements. The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands) December 31, 2016 Level 1 Level 2 Level 3 Total Financial liabilities Derivative liability $ — $ 4,595 $ — $ 4,595 Derivative liability — 1,575 — 1,575 Total financial liabilities $ — $ 6,170 $ — $ 6,170 December 31, 2015 Financial assets Derivative asset $ — $ 3,694 $ — $ 3,694 Total financial assets $ — $ 3,694 $ — $ 3,694 Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal. Fair Value on a Nonrecurring Basis The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and goodwill. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. Property Impairments Oil and gas properties are measured at fair value on a nonrecurring basis. The impairment charge reduces the carrying values of oil and gas properties’ to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets. See Note 6. Oil and Natural Gas Properties Goodwill Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. See Note 7. Goodwill Business Combinations The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 3 Acquisitions and Divestitures Asset Retirement Obligations The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. See Note 12 Asset Retirement Obligations

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Note 5. 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, 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 purposes. 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 (Loss) gain on derivative contracts, net 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 by counterparty, 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 each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency The Company had the following open crude oil and natural gas derivative contracts as of December 31, 2016: Price Swaps Period Commodity Volume (Bbl s Weighted Average Price ($/Bbl / $/MMBtu) Q1 - Q4 2017 Crude Oil 600,000 $ 50.38 Q1 - Q4 2018 Crude Oil 270,000 $ 50.70 Q1 - Q4 2017 Natural Gas 1,740,000 $ 2.997 Q1 - Q4 2018 Natural Gas 600,000 $ 2.907 The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets (in thousands) December 31, 2016 December 31, 2015 Derivatives not designated as hedging contracts under ASC Topic 815 Balance Sheet Location Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Commodity Derivative asset $ — $ — $ — $ 3,694 $ — $ 3,694 Commodity contracts Derivative liability $ 4,595 $ — $ 4,595 $ — $ — $ — Commodity contracts Derivative liability $ 1,575 $ — $ 1,575 $ — $ — $ — The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Company’s Consolidated Statements of Operations (in thousands) Years Ended December 31, 2016 2015 2014 Derivatives not designated as hedging contracts under ASC Topic 815 Statement of Operations Location Total (loss) gain on commodity contracts (Loss) gain on derivative contracts, net $ (9,863 ) $ 125 $ 3,614 Cash settlements on commodity contracts (Loss) gain on derivative contracts, net 3,225 6,306 778 (Loss) gain on commodity contracts, net $ (6,638 ) $ 6,431 $ 4,392

Oil and Natural Gas Properties

Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2016
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Oil and Natural Gas Properties	Note 6. Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, costs to acquire oil and gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Gains and losses arising from the sale of properties are included in operating income (loss) in the Consolidated Statements of Operations. The Company’s lease acquisition costs and development costs of proved oil and 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 $25.4 million, $30.7 million, and $18.1 million, for the years ended December 31, 2016, 2015, and 2014, respectively. Proved Properties The Company reviews its proved oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. Unproved Properties Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis. The Company reviews its unproved properties periodically for impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property The Company had the following non-cash asset impairment charges to its oil and natural gas properties for the years ended December 31, 2016, 2015 and 2014 ( in thousands Years Ended December 31, 2016 2015 2014 Proved property $ 2,873 $ 93,984 $ 16,903 Unproved property 3,878 42,555 2,456 Total $ 6,751 $ 136,539 $ 19,359 Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, 2016 and 2015, were $162.7 million and $155.9 million, respectively.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill	Note 7. Goodwill Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. The Company had the following non-cash impairment charges to its goodwill for the years ended December 31, 2016 and 2015 ( in thousands Years Ended December 31, 2016 2015 Impairment expense - goodwill $ 17,532 $ 1,547 The Company did not have any non-cash impairment charges to its goodwill for the year ended December 31, 2014. Accumulated impairments to Goodwill as of December 31, 2016 and 2015, were $19.1 million and $1.5 million, respectively.

Net Loss Per Common Share

Net Loss Per Common Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Loss Per Common Share	Note 8. Net Loss Per Common Share Net loss per common share—basic is calculated by dividing Net loss by the weighted average number of shares of common stock outstanding during the period. Net loss per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net loss by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net loss per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares would have an anti-dilutive effect. A reconciliation of Loss per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2016 2015 2014 Net loss $ (54,541 ) $ (116,655 ) $ (28,834 ) Net loss per common share: Basic $ (2.92 ) $ (8.43 ) $ (3.11 ) Diluted $ (2.92 ) $ (8.43 ) $ (3.11 ) Weighted average common shares outstanding Basic 18,651,582 13,835,128 9,279,324 Add potentially dilutive securities: Nonvested restricted stock units — — — Diluted weighted average common shares outstanding 18,651,582 13,835,128 9,279,324 For the year ended December 31, 2016, the Company excluded 52,844 shares for the dilutive effect of restricted stock units in calculating diluted earnings per share as the effect was anti-dilutive due to the net loss incurred this period. For the years ended December 31, 2015 and 2014, there were no restricted stock units issued or outstanding under the Company’s long-term incentive plan.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Common Stock	Note 9. Common Stock At December 31, 2016 and 2015, there were 22,289,177 and 13,835,128 shares of Common Stock issued, respectively, both including 15,357 shares of treasury stock held by the Company. During the year ended December 31, 2016, there were the following changes to the Common Stock: • On May 18, 2016, the Company acquired Lynden in an all-stock transaction issuing 3,700,279 shares of Common Stock, valued at $45.7 million on that date, to the holders of the common stock of Lynden. For additional information, see Note 3. Acquisitions and Divestitures . • On June 21, 2016, the Company completed a public offering of 4,753,770 shares of Common Stock at an issue price of $10.50 per share. The Company received net proceeds from this offering of $47.1 million, after deducting underwriters’ fees and offering expenses of $2.7 million. See Note 1. Organization and Basis of Presentation During the year ended December 31, 2015, there were no changes to the Common Stock. During the year ended December 31, 2014, there were the following changes to the Common Stock: • On December 19, 2014, pursuant to the Exchange Agreement, the Company issued 9,124,452 shares of Common Stock to OVR in exchange for the outstanding membership interests of OVR’s three subsidiaries and 1,753,388, provided as consideration, represented Earthstone’s legacy common stock, of which 15,357 shares represented Earthstone’s legacy treasury stock. For additional information, see Note 1. Organization and Basis of Presentation . • Immediately following the exchange, the Company, through its wholly owned subsidiary, Sabine, acquired an additional 20% undivided ownership interest in certain crude oil and natural gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of approximately 2,957,288 shares of Common Stock. For additional information, see Note 1. Organization and Basis of Presentation.

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock Based Compensation	The Company’s amended 2014 Long-term Incentive Plan (the “2014 Plan”) allows, among other things, for the grant of restricted stock units (“RSUs”). RSUs do not pay dividends or have voting rights prior to vesting. The Company determines the fair value of granted RSUs based on the market price of the Common Stock of the Company on the date of the grant. Compensation expense is for granted RSUs is recognized on a straight-line basis over the vesting and is net of forfeitures, as incurred. During the year ended December 31, 2016, the Company granted 754,500 RSU’s to employees of the Company and 27,000 RSUs to members of its Board of Directors (the “Awards”). The weighted average grant date fair value of the Awards was $12.53 per share. The future compensation cost of the Awards at December 31, 2016 is $6.5 million which will be amortized over the remaining vesting period. The weighted average remaining useful life of the future compensation cost is 0.74 years. Stock-based compensation for the year ended December 31, 2016 recorded in the Consolidated Statements of Operations was $3.3 million. There was no stock-based compensation for the years ended December 31, 2015 and 2014.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Note 11. Long Credit Facility In December, 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “Credit Agreement”). At December 31, 2016, borrowing base under the Credit Agreement was $80.0 million and is subject to redetermination on May 1 and November 1 each year, as well as other elective borrowing base redeterminations. As of December 31, 2016, outstanding borrowings under the Credit Agreement bear interest at a rate elected by the Company that is equal to a base rate (which is equal to the greater of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month LIBOR plus 1.00%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.25% to 2.25% for base rate loans and from 2.25% to 3.25% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee of 0.50% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. The Company is also required to pay customary letter of credit fees. Principal amounts outstanding under the Credit Agreement are due and payable in full at maturity on December 19, 2018. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. As of December 31, 2016, the Company had an $80.0 million borrowing base, of which $10.0 million of debt was outstanding, bearing an interest rate of 2.867%, as well as a $0.2 million letters of credit outstanding related to our office lease, resulting in $69.8 million of borrowing base availability under the Credit Agreement. The Credit Agreement contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period. As of December 31, 2016, the Company was in compliance with these covenants under the Credit Agreement. Promissory Note In July 2016, the Company issued a $5.1 million unsecured promissory note (the “Note”) to a drilling rig contractor in settlement of rig idle charges and a contract termination fee. These expenses were recognized in the Company’s Consolidated Statement of Operations in the line item Rig idle and contract termination expense The following table below summarizes long term debt ( in thousands December 31, 2016 2015 Borrowings under Credit Agreement $ 10,000 $ 11,191 Promissory note 4,297 — Total debt 14,297 11,191 Less: Current portion of long-term debt (1,604 ) — Long-term debt $ 12,693 $ 11,191 For the year ended December 31, 2016, we borrowed $36.6 million and made payments of $37.8 million under the Credit Agreement. For the year ended December 31, 2015, we had no borrowings or payments under the Credit Agreement. For the year ended December 31, 2014, we borrowed $11.2 million and made payments of $10.8 million under the Credit Agreement. For the years ended December 31, 2016, 2015 and 2014, interest on borrowings under the Credit Agreement averaged 2.94%, 1.68% and 2.16% per annum, respectively. Interest expense for the years ended December 31, 2016, 2015 and 2014, includes amortization of deferred financing costs of $0.3 million, $0.3 million, and $0.2 million, respectively. The Company capitalized $0.1 million, $0.1 million, and $0.6 million for the years ended December 31, 2016, 2015 and 2014, respectively, of deferred financing costs associated with borrowing under the Credit Agreement. These costs are included in Other noncurrent assets

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 12. Asset Retirement Obligations The Company has asset retirement obligations associated with the future plugging and abandonment of oil and gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate. The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended December 31, 2016 and 2015 (in thousands) 2016 2015 Beginning asset retirement obligations $ 5,075 $ 6,078 Liabilities incurred 165 126 Liabilities settled (15 ) (108 ) Accretion expense 551 550 Acquisitions (1) 250 — Purchase price adjustment (2) — (1,192 ) Property dispositions — (403 ) Revision of estimates (13 ) 24 Ending asset retirement obligations $ 6,013 $ 5,075 (1) See Note 3 Acquisitions and Divestitures (2) Note 3 Acquisition and Divestitures

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Note 13. Related Party Transactions FASB ASC Topic 850 , Related Party Disclosures Flatonia, which owns approximately 13.3% of our common stock, is a party to a joint operating agreement (the “Operating Agreement”) with OVO. This agreement was entered into prior to the closing of the Flatonia

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 14. Commitments and Contingencies Contractual Commitments Future minimum contractual commitments as of December 31, 2016 under non-cancelable agreements having remaining terms in excess of one year are as follows: 2017 2018 2019 2020 2021 Thereafter Gas contract $ 1,643 $ 1,643 $ 1,643 $ 1,647 $ 680 $ — Office leases 738 661 627 — — — Total $ 2,381 $ 2,304 $ 2,270 $ 1,647 $ 680 $ — The Company has a non-cancelable fixed cost agreement of $1.6 million per year through 2021 to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing related to certain Eagle Ford assets in south Texas through 2021.Additionally, the Company leases corporate office space in The Woodlands, Texas and Denver, Colorado. Rent expense was approximately $0.8 million, $0.8 million, and $0.4 million for the years ended December 31, 2016, 2015, and 2014, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2016 are shown in the table above. Environmental The Company’s operations are subject to risks normally associated with the drilling, completion and production of oil and gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Company to liabilities associated with these risks. In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks. However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above. Legal From time to time, the Company and its subsidiaries may be involved in various legal proceedings and claims in the ordinary course of business. In July 2015, EF Non-Op, LLC, a subsidiary of the Company, filed suit in the 125 th EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP),

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 15. Income Taxes The following table shows the components of the Company’s income tax provision for the years ended December 31, 2016, 2015 and 2014 ( in thousands Years Ended December 31, 2016 2015 2014 Current: Federal $ — $ — $ — State — 91 — Total current — 91 — Deferred: Federal 515 (26,214 ) 21,803 State 13 (319 ) 302 Total deferred 528 (26,533 ) 22,105 Total income tax provision (benefit) $ 528 $ (26,442 ) $ 22,105 Effective Tax Rate Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from the Lynden Arrangement that includes Lynden USA, Inc. (“Lynden US”), Earthstone Energy, Inc. (“Earthstone”), and Lynden Energy Corp. (the Canadian entity), As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US, Inc.be offset by tax attributes of Earthstone. A reconciliation of the effective tax rate to the statutory rate for the year ended December 31, 2016 rate is as follows ( in thousands, except percentages U.S. Canada Total Net loss before income taxes $ (54,032 ) $ 19 $ (54,013 ) Statutory rate 34 % 26 % Tax benefit computed at statutory rate (18,370 ) 5 (18,365 ) Non-deductible impairment of goodwill 5,961 — 5,961 Non-deductible transaction costs 878 — 878 Non-deductible general and administrative expenses 5 — 5 Return to accrual 15 — 15 State income taxes, net of Federal benefit (128 ) — (128 ) Valuation allowance 12,167 (5 ) 12,162 Total income tax expense $ 528 $ — $ 528 Effective tax rate -1.0 % 0.0 % -1.0 % During the year ended December 31, 2016, we recorded income tax expense related to Lynden of $0.5 million. For the remainder of the Company, we recorded an income tax benefit of $12.2 million as a result of the related pre-tax net losses which were offset by a full valuation allowance, as future realization of the related deferred tax asset cannot be assured. A reconciliation of the effective tax rate to the statutory rate for the years ended December 31, 2015 and 2014 rates is as follows ( in thousands, except percentages Years Ended December 31, 2015 2014 Net loss before income taxes $ (143,097 ) $ (6,729 ) Tax benefit computed at Federal statutory rate (48,653 ) (2,288 ) Non-taxable Oak Valley income prior to merger — (4,142 ) Deferred income tax arising from change in tax status of Oak — 28,347 Non-deductible general and administrative expenses 534 — Return to accrual (1,398 ) — State income taxes, net of Federal benefit (743 ) 188 Valuation allowance 23,818 — Total income tax (benefit) expense $ (26,442 ) $ 22,105 Effective tax rate 18.5 % -328.5 % The Company’s effective tax rate for the year ended December 31, 2015, is approximately 18.5% which is less than the U.S. Federal statutory tax rate primarily due to the increase in valuation allowance in 2015. The impairments recorded by the Company during 2015 reduced the book value of its properties below the tax basis; thereby, giving rise to a significant deferred tax asset associated with its oil and gas properties and putting the Company in an overall net deferred tax asset position prior to any realization assessment. The realizability of the Company’s deferred tax assets is not more likely-than-not, therefore the Company recorded a valuation allowance to reduce its overall net deferred tax asset portion to zero. Deferred Tax Assets And Liabilities The Company's deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities at December 31, 2016 and 2015 are as follows ( in thousands December 31, 2016 2015 Deferred noncurrent income tax assets (liabilities): Office and other equipment (48 ) (253 ) Oil & gas properties 7,428 23,177 Asset retirement obligation 2,042 1,788 Basis difference in subsidiary obligation (4,226 ) — Intangible assets 36 (7 ) Unrealized derivative loss (gain) 2,145 (1,284 ) Stock-based compensation 1,148 — Federal net operating loss carryforward 15,109 339 Other 186 59 Net deferred noncurrent tax assets 23,820 23,819 Valuation allowance (39,596 ) (23,819 ) Net deferred tax (liability) asset $ (15,776 ) $ — As of December 31, 2016, the Company has a valuation allowance recorded against its deferred tax assets of $39.6 million which is in excess of its Net deferred noncurrent tax assets of $23.8 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2016, the deferred tax assets and liabilities related to the two U.S. Federal income tax returns and one Canadian income tax return are a $36.0 million deferred tax asset, a $15.8 million deferred tax liability and a $3.6 million deferred tax asset, respectively. As of December 31, 2016, the Company has estimated U.S. net operating loss carryforwards of $36.4 million, the first expiring in 2034 and the last in 2036, and estimated Canadian net operating loss carryforwards of $10.0 million, the first expiring in 2024 and the last in 2036. The ability to utilize net operating losses and other tax attributes could be subject to a significant limitation if the Company were to undergo an ownership change for the purposes of Section 382 of the US Tax Code (“Sec 382”). The Company has an additional estimated U.S. net operating loss carryforward of $28.0 million limited by Sec 382 resulting from the Lynden Arrangement. The Company continues to evaluate the impact, if any, of potential Sec 382 limitations. Uncertain Tax Positions FASB ASC Topic 740, Income Taxes The Company files two federal income tax returns, one Canadian income tax return and various combined and separate filings in several state and local jurisdictions. The Company’s practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statement of Operations. As of December 31, 2016, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.

Supplemental Selected Quarterly

Supplemental Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Supplemental Selected Quarterly Financial Data (Unaudited)	Note 16. Supplemental Selected Quarterly Financial Data (Unaudited) First Second Third Fourth (In thousands, except per share data) Quarter Quarter Quarter Quarter 2016 Oil and gas revenues $ 6,810 $ 9,777 $ 10,530 $ 15,152 Loss from operations (6,836 ) (6,433 ) (4,316 ) (28,436 ) Net loss (6,421 ) (11,172 ) (3,900 ) (33,048 ) Net loss per common share Basic and diluted net loss per share $ (0.46 ) $ (0.69 ) $ (0.17 ) $ (1.48 ) 2015 Oil and gas revenues $ 11,242 $ 14,958 $ 13,033 $ 8,231 (Loss) income from operations (2,298 ) 281 (2,595 ) (144,617 ) Net (loss) income (1,114 ) (748 ) 1,718 (116,511 ) Net (loss) income per common share Basic and diluted net (loss) income per share $ (0.08 ) $ (0.05 ) $ 0.12 $ (8.43 ) Fourth quarter 2016 loss from operations includes a non-cash impairment charge of $6.8 million to its oil and natural gas properties, as discussed in Note 6. Oil and Natural Gas Properties Note76. Goodwill Note 11. Long-Term Debt Fourth quarter 2015 loss from operations includes a non-cash impairment charge of $136.5 million to its oil and natural gas properties, as discussed in Note 6. Oil and Natural Gas Properties Note 7. Goodwill Note 3. Acquisitions and Divestitures

Supplemental Information On Oil

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Oil and Gas Exploration and Production Industries Activities	SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) Costs Incurred Related to Oil and Gas Activities Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. The Company’s oil and gas activities for 2016, 2015 and 2014 were entirely within the United States of America. Costs incurred in oil and gas producing activities were as follows ( in thousands Years Ended December 31, 2016 (1) 2015 2014 Acquisition cost: Proved $ 48,116 $ 4,508 $ 74,728 Unproved 26,600 10,646 36,236 Exploration costs: Exploratory drilling — — — Geological and geophysical 5 142 111 Development costs 28,577 56,862 75,105 Total additions $ 103,298 $ 72,158 $ 186,180 (1) Acquisition costs incurred during 2016 consisted entirely of the assets acquired in the Lynden Arrangement described in Note 3. Acquisitions and Divestitures During each of the three years ended December 31, 2016, 2015 and 2014, additions to oil and gas properties of $0.2 million were recorded for estimated costs of future abandonment related to new wells drilled or acquired. For the years ended December 31, 2016, 2015 and 2014, the Company had no capitalized exploratory well costs. Capitalized Costs Capitalized costs, impairment, and depreciation, depletion and amortization relating to our oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2016 and 2015 are summarized below ( in thousands December 31, 2016 2015 Oil and gas properties, successful efforts method: Proved properties $ 476,832 $ 394,532 Accumulated impairment to proved properties (113,760 ) (110,888 ) Proved properties, net of accumulated impairments 363,072 283,644 Unproved properties 100,612 79,619 Accumulated impairment to Unproved properties (48,889 ) (45,010 ) Unproved properties, net of accumulated impairments 51,723 34,609 Total oil and gas properties, net of accumulated impairments 414,795 318,253 Accumulated depreciation, depletion and amortization (145,393 ) (119,920 ) Net oil and gas properties $ 269,402 $ 198,333 Oil and Natural Gas Reserves Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. The proved reserves estimates shown herein for the years ended December 31, 2016, 2015 and 2014 have been independently prepared by Cawley, Gillespie & Associates, Inc. The reserve information in these consolidated financial statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced. The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2016, 2015, and 2014 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 $42.75 per barrel, $50.28 per barrel, and $94.99 per barrel, respectively. The natural gas prices as of December 31, 2016, 2015 and 2014 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.48 per MMBtu, $2.59 per MMBtu and $4.30 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, 2016, 2015 and 2014 are as follows: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBOE) Balance - December 31, 2013 6,078 24,213 1,318 11,431 Extensions and discoveries 1,909 1,403 221 2,364 Purchases of minerals in place 7,025 6,064 437 8,473 Production (403 ) (2,132 ) (124 ) (882 ) Revision to previous estimates (806 ) 9,031 107 806 Balance - December 31, 2014 13,803 38,579 1,959 22,192 Extensions and discoveries 526 828 21 685 Sales of minerals in place (4 ) (8,040 ) — (1,344 ) Purchases of minerals in place 1,641 679 208 1,962 Production (904 ) (2,143 ) (176 ) (1,437 ) Revision to previous estimates (5,701 ) (16,565 ) (1,022 ) (9,484 ) Balance - December 31, 2015 9,361 13,338 990 12,574 Extensions and discoveries 345 285 30 423 Purchases of minerals in place 5,548 14,770 2,637 10,647 Production (878 ) (2,171 ) (225 ) (1,465 ) Revision to previous estimates (7,265 ) (5,821 ) (1,892 ) (10,128 ) Balance - December 31, 2016 7,111 20,401 1,540 12,051 Proved developed reserves: December 31, 2013 1,307 11,053 557 3,706 December 31, 2014 6,093 16,214 1,005 9,800 December 31, 2015 6,114 10,954 673 8,613 December 31, 2016 6,052 13,545 1,051 9,361 Proved undeveloped reserves: December 31, 2013 4,771 13,160 761 7,725 December 31, 2014 7,710 22,365 954 12,392 December 31, 2015 3,247 2,384 317 3,961 December 31, 2016 1,059 6,856 489 2,690 Total proved reserves decreased by 0.5 MMBoe during 2016 which primarily resulted from a 10.1 MMBoe downward reserve revision caused by decreases in the prices used to calculated those reserves (prices used to estimate reserves are included in Oil and Natural Gas Reserves At December 31, 2016 the Company’s estimated proved undeveloped reserves (PUDs) were 2.7 MMBoe, a 1.3 MMBoe net decrease over the previous year’s estimate of 4.0 MMBoe. The following details the changes in PUD reserves for 2016 ( in MBoe Proved undeveloped reserves at December 31, 2015 3,961 Conversions to developed (169 ) Extensions and discoveries 293 Purchases 873 Revisions (2,268 ) Proved undeveloped reserves at December 31, 2016 2,690 The change to the PUD reserves was a result of the significant decline in oil and natural gas prices. Prices used to estimate reserves are included in Oil and Natural Gas Reserves Extensions and Discoveries during the year ended December 31, 2016 were from the Company’s operated Eagle Ford and non-operated Bakken properties. All of the Company’s purchases of minerals in place reserves during the year ended December 31, 2015, occurred in the Eagle Ford property in Gonzales County, Texas. Based on the Company’s year-end 2015 reserve report, the Company expects to drill all of its PUD locations within five years. The total proved reserves increase of 10.8 MMBoe during 2014 is comprised of 6.1 MMBoe in proved developed and 4.7 MMBoe in proved undeveloped reserves. During 2014, the Company added 2.4 MMBoe in proved reserves due to extension and discoveries, the majority of which is due to successful drilling in its operated Eagle Ford property in Fayette and Gonzales counties, Texas. Both new wells drilled and completed during 2014 along with the PUD locations that were added because of this successful drilling contributed to the increase in proved reserves. Purchase of minerals in place of 8.5 MMBoe were as a result of the Exchanges Agreement whereby Oak Valley acquired the legacy Earthstone assets through a reverse acquisition and the Flatonia Contribution Agreement where the Company acquired additional interests in its operated Eagle Ford property. All of the Company’s increases through extensions and discoveries occurred in its operated Eagle Ford property in Fayette and Gonzales counties, Texas as a result of successful drilling during 2014 which added additional PUD locations as well. PUDs that were converted during the year occurred in both the Company’s operated Eagle Ford and non-operated Bakken properties and 62% of the conversions occurred in the Eagle Ford property. Extensions and Discoveries were from the Company’s operated Eagle Ford and non-operated Bakken properties. All of the Company’s purchases of PUD reserves occurred in the Eagle Ford property in Gonzales County, Texas. Based on the Company’s year-end 2016 reserve report, the Company expects to drill all of its PUD locations within five years. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. PUD locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC 932, Extractives Activities – Oil and Gas The Company believes that the following factors should be taken into account when reviewing the following information: • Future costs and commodity prices will probably differ from those required to be used in these calculations; • Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; • A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and • Future net revenues may be subject to different rates of income taxation At December 31, 2016, 2015 and 2014, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Prices used to estimate reserves are included in Oil and Natural Gas Reserves The Standardized Measure is as follows ( in thousands December 31, 2016 2015 2014 Future cash inflows $ 346,948 $ 481,131 $ 1,464,138 Future production costs (172,062 ) (192,349 ) (427,113 ) Future development costs (29,814 ) (91,725 ) (312,010 ) Future income tax expense — — (180,248 ) Future net cash flows 145,072 197,057 544,767 10% annual discount for estimated timing of cash flows (59,189 ) (92,661 ) (288,911 ) Standardized measure of discounted future cash flows $ 85,883 $ 104,396 $ 255,856 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, 2016 ( in thousands December 31, 2016 2015 2014 Beginning of year $ 104,396 $ 255,856 $ 125,357 Sales of oil and gas produced, net of production costs (24,998 ) (29,152 ) (35,794 ) Sales of minerals in place — (2,470 ) — Net changes in prices and production costs (102,143 ) (288,064 ) (34,681 ) Extensions, discoveries, and improved recoveries 241 6,514 54,157 Changes in income taxes, net (1) — 88,944 (88,944 ) Previously estimated development costs incurred during the 27,770 26,977 18,252 Net changes in future development costs 102,267 6,697 7,028 Purchases of minerals in place 16,921 7,695 163,309 Revisions of previous quantity estimates (45,239 ) (16,671 ) 16,283 Accretion of discount 11,506 25,586 12,536 Changes in timing of estimated cash flows and other (4,838 ) 22,484 18,353 End of year $ 85,883 $ 104,396 $ 255,856 (1) As a result of the December 19, 2014 Exchange, all historical financial information contained in this report is that of OVR and its subsidiaries. OVR,

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation.
Use of Estimates	Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods then ended. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of our estimates. All reserve data included in these Consolidated Financial Statements are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered. Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, goodwill, asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)
Accounts Receivable	Accounts Receivable Accounts receivable include amounts due from crude oil, natural gas, and natural gas liquids purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and natural gas liquids sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability. Allowance for uncollectible accounts receivable was $0.2 million at December 31, 2016 and 2015.
Derivative Instruments	Derivative Instruments The Company utilizes derivative instruments in order to manage exposure to commodity price risk associated with future oil and natural gas production. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are marked-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in (Loss) gain on derivative contracts, net (Loss) gain on derivative contracts, net
Oil and Gas Properties	Oil and Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the successful efforts method of accounting for natural gas properties as proscribed by the SEC. For more information see Note 6. Oil and Natural Gas Properties .
Goodwill	Goodwill Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. During the years ended December 31, 2016 and 2015, impairments to Goodwill of $17.5 million and $1.5 million, respectively, were recorded. There were no impairments to Goodwill recorded in the year ended December 31, 2014. For further discussion, see Note 7. Goodwill
Segment Reporting	Segment Reporting The Company’s operations are conducted through two locations which have been deemed operating segments under ASC 280, Segment Reporting. The Company aggregated them into one reporting segment because these operating segments sell the same products, under the same production processes, with the same type of customers, under the same method of distribution, and in the same type of regulatory environment.
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For further discussion, see Note 12. Asset Retirement Obligations
Business Combinations	Business Combinations The Company accounts for the acquisition of oil and gas properties not commonly controlled based on the requirements of FASB ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved developed oil and gas properties as business combinations.
Revenue Recognition	Revenue Recognition Oil, natural gas, and natural gas liquids revenues represent income from the production and delivery of oil, natural gas, and natural gas liquids, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has been transferred, and collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. The Company had no significant gas imbalances as of December 31, 2016, 2015, or 2014.
Concentration of Credit Risk	Concentration of Credit Risk Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms. The purchasers of the Company’s oil, natural gas, and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2016, two purchasers accounted for 41% and 19%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In 2015 and 2014, one purchaser accounted for 62% and 60% respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during 2016, 2015, and 2014. Additionally, at December 31, 2016, two purchasers accounted for 28% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. At December 31, 2015, one purchasers accounted for 25% of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2016 and 2015. The Company holds working interests in oil and gas properties for which a third party serves as operator. The operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. The Company recognizes the cash received as revenue. In 2016 and 2015, one operator distributed 19% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids revenues. In 2014, a different operator distributed 20% of the Company’s oil, natural gas and natural gas liquids revenues. The derivative instruments of the Company are with a small number of counterparties and, from time-to-time, may represent material assets in the Consolidated Balance Sheets. At December 31, 2016, the Company had no derivative contracts in asset positions. At December 31, 2015, two counterparties accounted for 69% and 31%, respectively, of the Company’s Current derivative asset in the Consolidated Balance Sheet. The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage.
Income Taxes	Income Taxes We are a U.S. company operating in multiple states, as well as one foreign legal entity, Lynden Energy Corp., which is a Canadian company discussed in Note 3. Acquisitions and Divestitures Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in our Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2016 and 2015, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets. The historical financials prior to December 19, 2014 are those of OVR. OVR was not subject to taxation and therefore tax provisions were not recorded on the historical consolidated financial statements. As a result of the Exchange Agreement, OVR is now a taxable entity and a charge to earnings to record a tax provision was included in the purchase accounting adjustments. The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2016, 2015 or 2014.
Recently Issued Accounting Standards	Recently Issued Accounting Standards Standards adopted in 2016 Debt Issuance Costs – In April 2015, the Financial Accounting Standards Board (“FASB”) issued updated guidance which changes the presentation of debt issuance costs in the financial statements. Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update was effective for interim and annual periods beginning after December 15, 2015. The Company adopted this standards update, as required, effective January 1, 2016. The adoption of this standards update did not affect the Company’s method of amortizing debt issuance costs and did not have a material impact on its Consolidated Financial Statements. Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination. The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standards update was effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The Company adopted this standard update, as required, effective January 1, 2016, which did not have a material impact on its Consolidated Financial Statements. Stock Compensation - In March 2016, the FASB issued updated guidance on share-based payment accounting. The standards update is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The standards update is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. The Company elected to early-adopt this standards update as of April 1, 2016 in connection with its initial grant of awards under the Company’s 2014 Long Term Incentive Plan. The Company has elected to record the impact of forfeitures on compensation cost as they occur. The Company is also permitted to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory tax rates. There was no retrospective adjustment as the Company did not have any outstanding equity awards prior to adoption. See . Standards not yet adopted Revenue Recognition - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. This update amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of good and services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those good or services. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company does not expect the adoption of this guidance to have a material impact on its Consolidated Financial Statements. Leases – In February 2016, the FASB issued updated guidance on accounting for leases. This update requires lessees to recognize a right of use asset and lease liability on the balance sheet for all leases, with the exception of short-term leases. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company will adopt this standards update, as required, beginning with the first quarter of 2019. The Company is currently evaluating the effect of the update on our consolidated financial statements and related disclosures. Statement of Cash Flows – In August 2016, the FASB issued updated guidance that These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2018. The Company is currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
Lynden Arrangement [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 transferred, fair value of assets acquired and liabilities assumed and resulting goodwill ( in thousands, except share and share price amount Consideration: Shares of Earthstone common stock issued in the Arrangement 3,700,279 Closing price of Earthstone common stock as of May 18, 2016 $ 12.35 Total consideration to Lynden shareholders $ 45,698 Fair Value of Liabilities Assumed: Credit facility (4) $ 36,597 Current liabilities 1,915 Deferred tax liability (1) 15,157 Asset retirement obligations 250 Total consideration plus liabilities assumed $ 99,617 Fair Value of Assets Acquired: Cash and cash equivalents (4) $ 5,263 Current assets 2,018 Proved oil and gas properties (2)(3) 48,116 Unproved oil and gas properties 26,600 Amount attributable to assets acquired $ 81,997 Goodwill (5) $ 17,620 (1) This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Lynden Arrangement, tax-effected using a tax rate of approximately 34.5%. (2) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $64.73 per barrel of oil, $3.68 per Mcf of natural gas and $19.34 per barrel of oil equivalent for natural gas liquids, after adjustments for transportation fees and regional price differentials. (3) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projecting of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4. Fair Value Measurements, (4) Concurrent with closing the Lynden Arrangement, the Company paid off the outstanding balance of $36.6 million on the Lynden credit facility. The settlement of the debt and the cash acquired is equal to the $31.3 million net cash outflow associated with the Lynden Arrangement. (5) Goodwill was determined to be the excess consideration exchanged over the fair value of the net assets of Lynden on May 18, 2016. The goodwill resulted from the expected synergies of the management team and balance sheet of the Company combined with the key assets acquired in the Midland Basin area. The goodwill recognized will not be deductible for tax purposes.
Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed	The following unaudited supplemental pro forma results of operations present consolidated information assuming the Lynden Arrangement had been completed as of January 1, 2014. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for the Company and Lynden and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired, (ii) accretion expense associated with the asset retirement obligations recorded using the Company’s assumptions about the future liabilities and (iii) interest expense based on the combined debt of the Company post-acquisition. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information ( in thousands, except per share amounts Years ended December 31, 2016 2015 2014 (Unaudited) Revenue $ 47,679 $ 62,817 $ 112,370 (Loss) income before taxes $ (53,510 ) $ (148,609 ) $ 32,912 Net (loss) income available to Earthstone common stockholders $ (54,744 ) $ (122,598 ) $ 19,518 Pro Forma net (loss) income per common share: Basic $ (2.73 ) $ (6.99 ) $ 1.11 Diluted $ (2.73 ) $ (6.99 ) $ 1.11
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 issued as consideration 1,753,388 Closing price of Common Stock as of December 19, 2014 $ 19.08 Total purchase price $ 33,455 Estimated Fair Value of Liabilities Assumed: Current liabilities $ 7,631 Long-term debt 7,000 Deferred tax liability (1) 2,880 Asset retirement obligation 1,035 Amount attributable to liabilities assumed 18,546 Total purchase price plus liabilities assumed $ 52,001 Estimated Fair Value of Assets Acquired: Cash (2) $ 2,920 Other current assets 3,466 Proved oil and natural gas properties (3) (4) 21,813 Unproved oil and natural gas properties 5,524 Other non-current assets 746 Amount attributable to assets acquired $ 34,469 Goodwill (5) $ 17,532 (1) This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Exchange, tax-effected using a tax rate of approximately 35%. (2) Net cash flow related to the Exchange was an outflow of $4.2 million which consisted of the $7.1 million repayment of long-term debt (plus accrued interest) less the cash acquired of $2.9 million. (3) 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. (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 4. Fair Value Measurements (5) Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. In 2016, due to the commodity price environment, the Company determined that the amount recorded was no longer recoverable and recognized a full impairment Note 7.Goodwill
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 2,957,288 Closing price of Common Stock as of December 19, 2014 $ 19.08 Total purchase price $ 56,425 Estimated Fair Value of Liabilities Assumed: Deferred tax liability (1) $ 1,547 Asset retirement obligation 173 Amount attributable to liabilities assumed 1,720 Total purchase price plus liabilities assumed $ 58,145 Estimated Fair Value of Assets Acquired: Proved oil and natural gas properties (2) (3) $ 34,745 Unproved oil and natural gas properties 21,853 Amount attributable to assets acquired $ 56,598 Goodwill (4) $ 1,547 (1) This amount represents the difference between the recorded book value and the tax basis of the oil and natural gas properties as of the date of the closing of the Flatonia Contribution Agreement, tax-effected using a tax rate of approximately 34%. (2) 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. (3) 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 4. Fair Value Measurements (4) Goodwill was determined as the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. In 2015, due to the commodity price environment, the Company determined that the goodwill balance was not recoverable and therefore fully impaired it, recording a goodwill impairment charge Note 7.Goodwill
Other Acquisitions [Member]
Business Acquisition [Line Items]
Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets	The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands) Purchase price $ 4,066 Estimated fair value of assets acquired: Proved oil and natural gas properties $ 588 Unproved oil and natural gas properties 3,496 Total assets acquired $ 4,084 Estimated fair value of liabilities assumed: Asset retirement obligations $ 13 Other liabilities 5 Total liabilities assumed $ 18 Consideration paid $ 4,066

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Summary of Fair Value of Financial Assets and Liabilities	The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands) December 31, 2016 Level 1 Level 2 Level 3 Total Financial liabilities Derivative liability $ — $ 4,595 $ — $ 4,595 Derivative liability — 1,575 — 1,575 Total financial liabilities $ — $ 6,170 $ — $ 6,170 December 31, 2015 Financial assets Derivative asset $ — $ 3,694 $ — $ 3,694 Total financial assets $ — $ 3,694 $ — $ 3,694

Derivative Financial Instrume29

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Open Crude Oil and Natural Gas Derivative Contracts	The Company had the following open crude oil and natural gas derivative contracts as of December 31, 2016: Price Swaps Period Commodity Volume (Bbl s Weighted Average Price ($/Bbl / $/MMBtu) Q1 - Q4 2017 Crude Oil 600,000 $ 50.38 Q1 - Q4 2018 Crude Oil 270,000 $ 50.70 Q1 - Q4 2017 Natural Gas 1,740,000 $ 2.997 Q1 - Q4 2018 Natural Gas 600,000 $ 2.907
Schedule of Location and Fair Value Amounts of All Derivative Instruments	The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets (in thousands) December 31, 2016 December 31, 2015 Derivatives not designated as hedging contracts under ASC Topic 815 Balance Sheet Location Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Gross Recognized Assets / Liabilities Gross Amounts Offset Net Recognized Assets / Liabilities Commodity Derivative asset $ — $ — $ — $ 3,694 $ — $ 3,694 Commodity contracts Derivative liability $ 4,595 $ — $ 4,595 $ — $ — $ — Commodity contracts Derivative liability $ 1,575 $ — $ 1,575 $ — $ — $ —
Summary of Realized and Unrealized Gains and Losses on Derivative Instruments	The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Company’s Consolidated Statements of Operations (in thousands) Years Ended December 31, 2016 2015 2014 Derivatives not designated as hedging contracts under ASC Topic 815 Statement of Operations Location Total (loss) gain on commodity contracts (Loss) gain on derivative contracts, net $ (9,863 ) $ 125 $ 3,614 Cash settlements on commodity contracts (Loss) gain on derivative contracts, net 3,225 6,306 778 (Loss) gain on commodity contracts, net $ (6,638 ) $ 6,431 $ 4,392

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Impairment Charges [Abstract]
Schedule of Non-Cash Asset Impairment Charges	The Company had the following non-cash asset impairment charges to its oil and natural gas properties for the years ended December 31, 2016, 2015 and 2014 ( in thousands Years Ended December 31, 2016 2015 2014 Proved property $ 2,873 $ 93,984 $ 16,903 Unproved property 3,878 42,555 2,456 Total $ 6,751 $ 136,539 $ 19,359

Goodwill (Tables)

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

Net Loss Per Common Share (Tabl

Net Loss Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Reconciliation of Loss Per Common Share	A reconciliation of Loss per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2016 2015 2014 Net loss $ (54,541 ) $ (116,655 ) $ (28,834 ) Net loss per common share: Basic $ (2.92 ) $ (8.43 ) $ (3.11 ) Diluted $ (2.92 ) $ (8.43 ) $ (3.11 ) Weighted average common shares outstanding Basic 18,651,582 13,835,128 9,279,324 Add potentially dilutive securities: Nonvested restricted stock units — — — Diluted weighted average common shares outstanding 18,651,582 13,835,128 9,279,324

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Summary of Long Term Debt	The following table below summarizes long term debt ( in thousands December 31, 2016 2015 Borrowings under Credit Agreement $ 10,000 $ 11,191 Promissory note 4,297 — Total debt 14,297 11,191 Less: Current portion of long-term debt (1,604 ) — Long-term debt $ 12,693 $ 11,191

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Summary of Asset Retirement Obligation Transactions	The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended December 31, 2016 and 2015 (in thousands) 2016 2015 Beginning asset retirement obligations $ 5,075 $ 6,078 Liabilities incurred 165 126 Liabilities settled (15 ) (108 ) Accretion expense 551 550 Acquisitions (1) 250 — Purchase price adjustment (2) — (1,192 ) Property dispositions — (403 ) Revision of estimates (13 ) 24 Ending asset retirement obligations $ 6,013 $ 5,075 (1) See Note 3 Acquisitions and Divestitures (2) Note 3 Acquisition and Divestitures

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Contractual Commitments under Non-cancelable Agreements	Future minimum contractual commitments as of December 31, 2016 under non-cancelable agreements having remaining terms in excess of one year are as follows: 2017 2018 2019 2020 2021 Thereafter Gas contract $ 1,643 $ 1,643 $ 1,643 $ 1,647 $ 680 $ — Office leases 738 661 627 — — — Total $ 2,381 $ 2,304 $ 2,270 $ 1,647 $ 680 $ —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Components of Income Tax Provision	The following table shows the components of the Company’s income tax provision for the years ended December 31, 2016, 2015 and 2014 ( in thousands Years Ended December 31, 2016 2015 2014 Current: Federal $ — $ — $ — State — 91 — Total current — 91 — Deferred: Federal 515 (26,214 ) 21,803 State 13 (319 ) 302 Total deferred 528 (26,533 ) 22,105 Total income tax provision (benefit) $ 528 $ (26,442 ) $ 22,105
Reconciliation of Effective Tax Rate to Statutory Rate	A reconciliation of the effective tax rate to the statutory rate for the year ended December 31, 2016 rate is as follows ( in thousands, except percentages U.S. Canada Total Net loss before income taxes $ (54,032 ) $ 19 $ (54,013 ) Statutory rate 34 % 26 % Tax benefit computed at statutory rate (18,370 ) 5 (18,365 ) Non-deductible impairment of goodwill 5,961 — 5,961 Non-deductible transaction costs 878 — 878 Non-deductible general and administrative expenses 5 — 5 Return to accrual 15 — 15 State income taxes, net of Federal benefit (128 ) — (128 ) Valuation allowance 12,167 (5 ) 12,162 Total income tax expense $ 528 $ — $ 528 Effective tax rate -1.0 % 0.0 % -1.0 % A reconciliation of the effective tax rate to the statutory rate for the years ended December 31, 2015 and 2014 rates is as follows ( in thousands, except percentages Years Ended December 31, 2015 2014 Net loss before income taxes $ (143,097 ) $ (6,729 ) Tax benefit computed at Federal statutory rate (48,653 ) (2,288 ) Non-taxable Oak Valley income prior to merger — (4,142 ) Deferred income tax arising from change in tax status of Oak — 28,347 Non-deductible general and administrative expenses 534 — Return to accrual (1,398 ) — State income taxes, net of Federal benefit (743 ) 188 Valuation allowance 23,818 — Total income tax (benefit) expense $ (26,442 ) $ 22,105 Effective tax rate 18.5 % -328.5 %
Components of Deferred Tax Assets and Liabilities	Significant components of the deferred tax assets and liabilities at December 31, 2016 and 2015 are as follows ( in thousands December 31, 2016 2015 Deferred noncurrent income tax assets (liabilities): Office and other equipment (48 ) (253 ) Oil & gas properties 7,428 23,177 Asset retirement obligation 2,042 1,788 Basis difference in subsidiary obligation (4,226 ) — Intangible assets 36 (7 ) Unrealized derivative loss (gain) 2,145 (1,284 ) Stock-based compensation 1,148 — Federal net operating loss carryforward 15,109 339 Other 186 59 Net deferred noncurrent tax assets 23,820 23,819 Valuation allowance (39,596 ) (23,819 ) Net deferred tax (liability) asset $ (15,776 ) $ —

Supplemental Selected Quarter37

Supplemental Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Selected Quarterly Financial Data	First Second Third Fourth (In thousands, except per share data) Quarter Quarter Quarter Quarter 2016 Oil and gas revenues $ 6,810 $ 9,777 $ 10,530 $ 15,152 Loss from operations (6,836 ) (6,433 ) (4,316 ) (28,436 ) Net loss (6,421 ) (11,172 ) (3,900 ) (33,048 ) Net loss per common share Basic and diluted net loss per share $ (0.46 ) $ (0.69 ) $ (0.17 ) $ (1.48 ) 2015 Oil and gas revenues $ 11,242 $ 14,958 $ 13,033 $ 8,231 (Loss) income from operations (2,298 ) 281 (2,595 ) (144,617 ) Net (loss) income (1,114 ) (748 ) 1,718 (116,511 ) Net (loss) income per common share Basic and diluted net (loss) income per share $ (0.08 ) $ (0.05 ) $ 0.12 $ (8.43 )

Supplemental Information On O38

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Costs Incurred in Oil and Gas Producing Activities	The Company’s oil and gas activities for 2016, 2015 and 2014 were entirely within the United States of America. Costs incurred in oil and gas producing activities were as follows ( in thousands Years Ended December 31, 2016 (1) 2015 2014 Acquisition cost: Proved $ 48,116 $ 4,508 $ 74,728 Unproved 26,600 10,646 36,236 Exploration costs: Exploratory drilling — — — Geological and geophysical 5 142 111 Development costs 28,577 56,862 75,105 Total additions $ 103,298 $ 72,158 $ 186,180 (1) Acquisition costs incurred during 2016 consisted entirely of the assets acquired in the Lynden Arrangement described in Note 3. Acquisitions and Divestitures
Summary of Capitalized Costs, Impairment, and Depreciation, Depletion and Amortization	Capitalized costs, impairment, and depreciation, depletion and amortization relating to our oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2016 and 2015 are summarized below ( in thousands December 31, 2016 2015 Oil and gas properties, successful efforts method: Proved properties $ 476,832 $ 394,532 Accumulated impairment to proved properties (113,760 ) (110,888 ) Proved properties, net of accumulated impairments 363,072 283,644 Unproved properties 100,612 79,619 Accumulated impairment to Unproved properties (48,889 ) (45,010 ) Unproved properties, net of accumulated impairments 51,723 34,609 Total oil and gas properties, net of accumulated impairments 414,795 318,253 Accumulated depreciation, depletion and amortization (145,393 ) (119,920 ) Net oil and gas properties $ 269,402 $ 198,333
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, 2016, 2015 and 2014 are as follows: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBOE) Balance - December 31, 2013 6,078 24,213 1,318 11,431 Extensions and discoveries 1,909 1,403 221 2,364 Purchases of minerals in place 7,025 6,064 437 8,473 Production (403 ) (2,132 ) (124 ) (882 ) Revision to previous estimates (806 ) 9,031 107 806 Balance - December 31, 2014 13,803 38,579 1,959 22,192 Extensions and discoveries 526 828 21 685 Sales of minerals in place (4 ) (8,040 ) — (1,344 ) Purchases of minerals in place 1,641 679 208 1,962 Production (904 ) (2,143 ) (176 ) (1,437 ) Revision to previous estimates (5,701 ) (16,565 ) (1,022 ) (9,484 ) Balance - December 31, 2015 9,361 13,338 990 12,574 Extensions and discoveries 345 285 30 423 Purchases of minerals in place 5,548 14,770 2,637 10,647 Production (878 ) (2,171 ) (225 ) (1,465 ) Revision to previous estimates (7,265 ) (5,821 ) (1,892 ) (10,128 ) Balance - December 31, 2016 7,111 20,401 1,540 12,051 Proved developed reserves: December 31, 2013 1,307 11,053 557 3,706 December 31, 2014 6,093 16,214 1,005 9,800 December 31, 2015 6,114 10,954 673 8,613 December 31, 2016 6,052 13,545 1,051 9,361 Proved undeveloped reserves: December 31, 2013 4,771 13,160 761 7,725 December 31, 2014 7,710 22,365 954 12,392 December 31, 2015 3,247 2,384 317 3,961 December 31, 2016 1,059 6,856 489 2,690
Changes in PUD reserves	Proved undeveloped reserves at December 31, 2015 3,961 Conversions to developed (169 ) Extensions and discoveries 293 Purchases 873 Revisions (2,268 ) Proved undeveloped reserves at December 31, 2016 2,690
Schedule Of Standardized Measure	The Standardized Measure is as follows ( in thousands December 31, 2016 2015 2014 Future cash inflows $ 346,948 $ 481,131 $ 1,464,138 Future production costs (172,062 ) (192,349 ) (427,113 ) Future development costs (29,814 ) (91,725 ) (312,010 ) Future income tax expense — — (180,248 ) Future net cash flows 145,072 197,057 544,767 10% annual discount for estimated timing of cash flows (59,189 ) (92,661 ) (288,911 ) Standardized measure of discounted future cash flows $ 85,883 $ 104,396 $ 255,856
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, 2016 ( in thousands December 31, 2016 2015 2014 Beginning of year $ 104,396 $ 255,856 $ 125,357 Sales of oil and gas produced, net of production costs (24,998 ) (29,152 ) (35,794 ) Sales of minerals in place — (2,470 ) — Net changes in prices and production costs (102,143 ) (288,064 ) (34,681 ) Extensions, discoveries, and improved recoveries 241 6,514 54,157 Changes in income taxes, net (1) — 88,944 (88,944 ) Previously estimated development costs incurred during the 27,770 26,977 18,252 Net changes in future development costs 102,267 6,697 7,028 Purchases of minerals in place 16,921 7,695 163,309 Revisions of previous quantity estimates (45,239 ) (16,671 ) 16,283 Accretion of discount 11,506 25,586 12,536 Changes in timing of estimated cash flows and other (4,838 ) 22,484 18,353 End of year $ 85,883 $ 104,396 $ 255,856 (1) As a result of the December 19, 2014 Exchange, all historical financial information contained in this report is that of OVR and its subsidiaries. OVR,

Organization and Basis of Pre39

Organization and Basis of Presentation - Additional Information (Details)	Dec. 19, 2014Subsidiary
Oak Valley Resources, LLC [Member]
Organization And Basis Of Presentation [Line Items]
Number of subsidiaries	3

Summary of Significant Accoun40

Summary of Significant Accounting Policies - Additional Information - (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2016USD ($)Contract	Dec. 31, 2015USD ($)Counterparty	Dec. 31, 2016USD ($)SegmentCustomerOperatorContract	Dec. 31, 2015USD ($)CustomerOperatorCounterparty	Dec. 31, 2014USD ($)CustomerOperator
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts receivable | $	$ 200,000	$ 200,000	$ 200,000	$ 200,000
Impairment of goodwill | $	$ 17,500,000	$ 1,600,000	$ 17,532,000	$ 1,547,000	$ 0
Number of reportable segment | Segment			1
Number of major operators | Operator			1	1
Number of other operators accounted for 10% or more of revenue | Operator			0	0	0
Derivative, number of counterparties | Counterparty		2		2
Derivative asset, Number of derivative contracts | Contract	0		0
Liability for uncertain tax positions | $	$ 0	$ 0	$ 0	$ 0	$ 0
Customer Concentration Risk [Member] | Sales Revenue Net [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of major customer			2	1	1
Number of other customer accounted for 10% or more of revenues			0	0	0
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Customer One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			41.00%	62.00%	60.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Customer Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			19.00%
Customer Concentration Risk [Member] | Sales Revenue Net [Member] | Operator One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			19.00%	12.00%	20.00%
Customer Concentration Risk [Member] | Accounts Receivable [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of major customer			2	1
Number of other customer accounted for 10% or more of receivables			0	0
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Customer Three [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			28.00%	25.00%
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Customer Four [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk			12.00%
Credit Concentration Risk [Member] | Current Derivative Asset [Member] | Counterparty One [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk				69.00%
Credit Concentration Risk [Member] | Current Derivative Asset [Member] | Counterparty Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk				31.00%

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details)	Jun. 21, 2016shares	May 18, 2016USD ($)$ / sharesshares	Dec. 19, 2014USD ($)Subsidiaryshares	Aug. 31, 2015USD ($)a	Jun. 30, 2015USD ($)aBoeWell	Apr. 30, 2015USD ($)	Jun. 30, 2015USD ($)a	Dec. 31, 2016USD ($)a	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Common stock issued, net of offering costs and contributions, shares | shares	4,753,770
Cash consideration						$ 3,400,000
Gain (loss) on sale of properties						$ 1,600	$ 1,600,000	$ 8,000	$ 1,617,000
Effective date of transaction						Mar. 1, 2015
Southern Gonzales County [Member]
Business Acquisition [Line Items]
Acquisition of operating interests				33.00%	50.00%
Company acquired gross acres | a				1,650	1,000		1,000
Number of wells acquired | Well					2
Percentage of acres held for production					100.00%
Gross production, barrels of oil equivalents per day | Boe					44
Working interest acquired				$ 3,300,000
Northern Kames County [Member]
Business Acquisition [Line Items]
Company acquired gross acres | a					400		400	350
Net acres | a								117
Banks Field of McKenzie County [Member]
Business Acquisition [Line Items]
Number of wells acquired | Well					41
Total consideration					$ 1,400,000
Purchase price adjustment for revenues, net for production taxes, operating expenses and capital costs					$ 2,000,000
Net acres acquired | a					164
Number of drilling wells acquired | Well					21
Lynden Arrangement [Member]
Business Acquisition [Line Items]
Common stock issued, net of offering costs and contributions, shares | shares		3,700,279
Common stock, price per share | $ / shares		$ 0.001
Total consideration		$ 45,698,000						$ 45,699,000
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Common stock issued, net of offering costs and contributions, shares | shares			9,124,000
Number of subsidiaries | Subsidiary			3
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Percentage of oil and natural gas property interests held by a wholly owned subsidiary			28.57%
Common stock shares issued in exchange for acquisition | shares			2,957,288
Total consideration			$ 56,425,000							$ 56,425,000

Acquisitions and Divestitures42

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Details) - USD ($) $ / shares in Units, $ in Thousands	May 18, 2016	Dec. 19, 2014	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2015
Business Acquisition [Line Items]
Total shares of Common Stock outstanding following the Exchange				22,273,820		13,819,771
Estimated Fair Value of Assets Acquired:
Goodwill				$ 17,620		$ 17,532
Lynden Arrangement [Member]
Business Acquisition [Line Items]
Shares of Common Stock issued in the Exchange/Arrangement	3,700,279
Closing price of Common Stock	$ 12.35
Total consideration	$ 45,698			$ 45,699
Estimated Fair Value of Liabilities Assumed:
Credit facility	36,597
Current liabilities	1,915
Deferred tax liability	15,157
Asset retirement obligations	250
Total consideration plus liabilities assumed	99,617
Estimated Fair Value of Assets Acquired:
Cash and cash equivalents	5,263
Current assets	2,018
Amount attributable to assets acquired	81,997
Goodwill	17,620
Lynden Arrangement [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	48,116
Lynden Arrangement [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	$ 26,600
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Shares of Common Stock issued as consideration		1,753,388
Closing price of Common Stock		$ 19.08
Total purchase price		$ 33,455
Estimated Fair Value of Liabilities Assumed:
Credit facility		7,000
Current liabilities		7,631
Deferred tax liability		2,880
Asset retirement obligations		1,035
Amount attributable to liabilities assumed		18,546
Total consideration plus liabilities assumed		52,001
Estimated Fair Value of Assets Acquired:
Cash and cash equivalents		2,920
Other current assets		3,466
Other non-current assets		746
Amount attributable to assets acquired		34,469
Goodwill		17,532
Earthstone Energy Reverse Acquisition [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		21,813
Earthstone Energy Reverse Acquisition [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		$ 5,524
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Shares of Common Stock issued as consideration in the Contribution		2,957,288
Closing price of Common Stock		$ 19.08
Total consideration		$ 56,425			$ 56,425
Estimated Fair Value of Liabilities Assumed:
Deferred tax liability		1,547
Asset retirement obligations		173
Amount attributable to liabilities assumed		1,720
Total consideration plus liabilities assumed		58,145
Estimated Fair Value of Assets Acquired:
Amount attributable to assets acquired		56,598
Goodwill		1,547
2014 Eagle Ford Properties [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		34,745
2014 Eagle Ford Properties [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		$ 21,853
Other Acquisitions [Member]
Business Acquisition [Line Items]
Total consideration			$ 4,066
Estimated Fair Value of Liabilities Assumed:
Asset retirement obligations			13
Other liabilities			5
Amount attributable to liabilities assumed			18
Total consideration plus liabilities assumed			4,066
Estimated Fair Value of Assets Acquired:
Amount attributable to assets acquired			4,084
Other Acquisitions [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties			588
Other Acquisitions [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties			$ 3,496

Acquisitions and Divestitures43

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Parenthetical) (Details)	May 18, 2016USD ($)$ / bbl$ / Mcf$ / Boe	Dec. 19, 2014USD ($)$ / bbl$ / Mcf	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Goodwill impairment charge			$ 17,500,000	$ 1,600,000	$ 17,532,000	$ 1,547,000	$ 0
Lynden Arrangement [Member]
Business Acquisition [Line Items]
Tax rate	34.50%
Weighted average commodity prices of oil | $ / bbl	64.73
Weighted average commodity prices of natural gas | $ / Mcf	3.68
Weighted average commodity prices of oil equivalent for natural gas liquids | $ / Boe	19.34
Credit facility, outstanding balance paid off	$ 36,597,000
Settlement of debt	31,300,000
Net cash outflow					31,334,000
Cash	$ 5,263,000
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Tax rate		35.00%
Weighted average commodity prices of oil | $ / bbl		51.62
Weighted average commodity prices of natural gas | $ / Mcf		4.58
Credit facility, outstanding balance paid off		$ 7,000,000
Net cash outflow		4,200,000
Repayment of long-term debt		7,100,000
Cash		$ 2,920,000
Goodwill impairment charge					$ 17,500,000
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Tax rate		34.00%
Weighted average commodity prices of oil | $ / bbl		56.36
Weighted average commodity prices of natural gas | $ / Mcf		3.36
Goodwill impairment charge						$ 1,500,000

Acquisitions and Divestitures44

Acquisitions and Divestitures - Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed (Details) - Lynden Arrangement [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Revenue	$ 47,679	$ 62,817	$ 112,370
(Loss) income before taxes	(53,510)	(148,609)	32,912
Net (loss) income available to Earthstone common stockholders	$ (54,744)	$ (122,598)	$ 19,518
Pro Forma net (loss) income per common share:
Basic	$ (2.73)	$ (6.99)	$ 1.11
Diluted	$ (2.73)	$ (6.99)	$ 1.11

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details)	Dec. 31, 2016USD ($)
Fair Value Disclosures [Abstract]
Fair value assets transfer from Level 1 to Level 2	$ 0
Fair value assets transfer from Level 2 to Level 1	0
Fair value liabilities transfer from Level 1 to Level 2	0
Fair value liabilities transfer from Level 2 to Level 1	$ 0

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Financial liabilities
Derivative liability	$ 4,595
Derivative liability	1,575
Financial assets
Derivative asset		$ 3,694
Fair Value on a Recurring Basis [Member]
Financial liabilities
Derivative liability	4,595
Derivative liability	1,575
Total financial liabilities	6,170
Financial assets
Derivative asset		3,694
Total financial assets		3,694
Level 2 [Member] | Fair Value on a Recurring Basis [Member]
Financial liabilities
Derivative liability	4,595
Derivative liability	1,575
Total financial liabilities	$ 6,170
Financial assets
Derivative asset		3,694
Total financial assets		$ 3,694

Derivative Financial Instrume47

Derivative Financial Instruments - Schedule of Open Crude Oil and Natural Gas Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2016MMBTU$ / bbl$ / MMBTUbbl
Price Swaps Q1 - Q4 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | MMBTU	1,740,000
Weighted Average Price | $ / MMBTU	2.997
Price Swaps Q1 - Q4 2017 [Member] | Crude Oil [Member]
Derivative [Line Items]
Volume | bbl	600,000
Weighted Average Price | $ / bbl	50.38
Price Swaps Q1 - Q4 2018 [Member] | Natural Gas [Member]
Derivative [Line Items]
Volume | MMBTU	600,000
Weighted Average Price | $ / MMBTU	2.907
Price Swaps Q1 - Q4 2018 [Member] | Crude Oil [Member]
Derivative [Line Items]
Volume | bbl	270,000
Weighted Average Price | $ / bbl	50.70

Derivative Financial Instrume48

Derivative Financial Instruments - Schedule of Location and Fair Value Amounts of All Derivative Instruments (Details) - Derivatives Not Designated as Hedging Contracts [Member] - Commodity Contracts [Member] - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Assets		$ 3,694
Net Recognized Assets		$ 3,694
Derivative Liability [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Liabilities	$ 4,595
Net Recognized Liabilities	4,595
Derivative Liability [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Liabilities	1,575
Net Recognized Liabilities	$ 1,575

Derivative Financial Instrume49

Derivative Financial Instruments - Summary of Realized and Unrealized Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments Gain Loss [Line Items]
Cash settlements on commodity contracts	$ (3,225)	$ (6,306)	$ (778)
(Loss) gain on commodity contracts, net	(6,638)	6,431	4,392
Derivatives Not Designated as Hedging Contracts [Member] | (Loss) Gain On Derivative Contracts, Net [Member]
Derivative Instruments Gain Loss [Line Items]
Total (loss) gain on commodity contracts	(9,863)	125	3,614
Cash settlements on commodity contracts	$ 3,225	$ 6,306	$ 778

Oil and Natural Gas Propertie50

Oil and Natural Gas Properties - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil And Natural Gas Properties [Line Items]
Accumulated impairments to proved and unproved oil and natural gas properties	$ 162.7	$ 155.9
Proved Oil and Gas Properties [Member]
Oil And Natural Gas Properties [Line Items]
Depletion expenses	$ 25.4	$ 30.7	$ 18.1
Unproved Oil and Gas Properties [Member] | Minimum [Member]
Oil And Natural Gas Properties [Line Items]
Unproved oil and gas lease term	3 years
Unproved Oil and Gas Properties [Member] | Maximum [Member]
Oil And Natural Gas Properties [Line Items]
Unproved oil and gas lease term	5 years

Oil and Natural Gas Propertie51

Oil and Natural Gas Properties - Schedule of Non-Cash Asset Impairment Charges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Impairment Charges [Line Items]
Asset impairment charges	$ 6,751	$ 136,539	$ 19,359
Proved Property [Member]
Asset Impairment Charges [Line Items]
Asset impairment charges	2,873	93,984	16,903
Unproved Property [Member]
Asset Impairment Charges [Line Items]
Asset impairment charges	$ 3,878	$ 42,555	$ 2,456

Goodwill - Summary of Non-Cash

Goodwill - Summary of Non-Cash Impairment Charges to Goodwill - (Details) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment of goodwill	$ 17,500,000	$ 1,600,000	$ 17,532,000	$ 1,547,000	$ 0

Goodwill - Additional Informati

Goodwill - Additional Information (Detail) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment of goodwill	$ 17,500,000	$ 1,600,000	$ 17,532,000	$ 1,547,000	$ 0
Accumulated impairments to goodwill	$ 19,100,000	$ 1,500,000	$ 19,100,000	$ 1,500,000

Net Loss Per Common Share - Rec

Net Loss Per Common Share - Reconciliation of Loss Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Net loss	$ (33,048)	$ (3,900)	$ (11,172)	$ (6,421)	$ (116,511)	$ 1,718	$ (748)	$ (1,114)	$ (54,541)	$ (116,655)	$ (28,834)
Net loss per common share:
Basic									$ (2.92)	$ (8.43)	$ (3.11)
Diluted									$ (2.92)	$ (8.43)	$ (3.11)
Weighted average common shares outstanding
Basic									18,651,582	13,835,128	9,279,324
Add potentially dilutive securities:
Diluted weighted average common shares outstanding									18,651,582	13,835,128	9,279,324

Net Loss Per Common Share - Add

Net Loss Per Common Share - Additional Information (Details) - Restricted Stock Units [Member] - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Dilutive effect of restricted stock units excluded from calculating diluted earnings per share	52,844
2014 Long Term Incentive Plan [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares issued		0	0
Shares outstanding		0	0

Common Stock - Additional Infor

Common Stock - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Jun. 21, 2016	May 18, 2016	Dec. 19, 2014	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2015
Capital Unit [Line Items]
Common stock, shares issued				22,289,177		13,835,128
Treasury stock, shares				15,357		15,357
Common stock issued, net of offering costs and contributions, shares	4,753,770
Shares issued, price per share	$ 10.50
Net proceeds from issuance of common stock	$ 47,100			$ 47,125
Stock issuance costs	$ 2,700			2,700
Lynden Arrangement [Member]
Capital Unit [Line Items]
Total consideration		$ 45,698		$ 45,699
Common stock issued, net of offering costs and contributions, shares		3,700,279
Flatonia Energy, LLC [Member]
Capital Unit [Line Items]
Additional ownership interest acquired in certain crude oil and natural gas properties					20.00%
Common Stock [Member]
Capital Unit [Line Items]
Common stock issued, net of offering costs and contributions, shares				4,753,770
Common Stock [Member] | Lynden Arrangement [Member]
Capital Unit [Line Items]
Reverse acquisition, shares		3,700,279		3,700,279
Total consideration		$ 45,700
Common Stock [Member] | Oak Valley Resources, LLC [Member]
Capital Unit [Line Items]
Reverse acquisition, shares			9,124,452		1,753,388
Reverse acquisition, shares			1,753,388
Common Stock [Member] | Flatonia Energy, LLC [Member]
Capital Unit [Line Items]
Reverse acquisition, shares					2,957,288
Treasury Stock [Member] | Oak Valley Resources, LLC [Member]
Capital Unit [Line Items]
Treasury stock, shares					15,357
Reverse acquisition, shares					(15,357)

Stock Based Compensation - Addi

Stock Based Compensation - Additional Information (Details) - 2014 Long Term Incentive Plan [Member] - Restricted Stock Units [Member] - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, Weighted average grant date fair value	$ 12.53
Future compensation cost	$ 6,500,000
Weighted average remaining useful life of future compensation	8 months 27 days
Stock-based compensation	$ 3,300	$ 0	$ 0
Employees [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted	754,500
Board of Directors [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted	27,000

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Details) - USD ($)	1 Months Ended		12 Months Ended
	Jul. 31, 2016	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt			$ 12,693,000	$ 11,191,000
Current portion of long-term debt			1,604,000
Amortization of deferred financing costs			$ 298,000	$ 264,000	$ 164,000
Interest rate on borrowings			2.94%	1.68%	2.16%
Other Noncurrent Assets [Member]
Debt Instrument [Line Items]
Deferred financing cost		$ 600,000	$ 100,000	$ 100,000	$ 600,000
Unsecured Promissory Note [Member]
Debt Instrument [Line Items]
Line of credit, maturity period	3 years
Long-term debt			$ 4,300,000
Debt instrument, principal amount	$ 5,100,000
Debt Instrument, frequency of periodic payment			monthly
Debt Instrument, maturity date	2019-07
Debt instrument, interest rate payment percentage for first 12 months	8.00%
Debt instrument, interest rate payment percentage for subsequent 12 months	10.00%
Debt instrument, interest rate payment percentage for last 12 months	12.00%
Current portion of long-term debt			$ 1,600,000
Pre-payment penalty	$ 0
Debt instrument, effective interest rate percentage	9.10%
Four Year Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 500,000,000			500,000,000
Line of credit, maturity period		4 years
Current borrowing base under credit agreement			$ 80,000,000
Commitment fee percentage			0.50%
Debt outstanding maturity			Dec. 19, 2018
Long-term debt			$ 10,000,000
Long-term debt, percentage bearing interest rate			2.867%
Letters of credit outstanding amount			$ 200,000
Borrowing base available under credit agreement			$ 69,800,000
Line of credit facility, covenant terms			The Credit Agreement contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period.
Borrowings under the credit agreement		$ 11,200,000	$ 36,600,000	0	11,200,000
Payments under the credit agreement			$ 37,800,000	$ 0	$ 10,800,000
Four Year Senior Secured Revolving Credit Facility [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage			0.50%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member]
Debt Instrument [Line Items]
Applicable margin percentage			1.00%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage			2.25%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage			3.25%
Four Year Senior Secured Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage			1.25%
Four Year Senior Secured Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage			2.25%

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total debt	$ 14,297	$ 11,191
Less: Current portion of long-term debt	(1,604)
Long-term debt	12,693	11,191
Promissory Note [Member]
Debt Instrument [Line Items]
Total debt	4,297
Less: Current portion of long-term debt	(1,600)
Long-term debt	4,300
Credit Agreement [Member]
Debt Instrument [Line Items]
Total debt	10,000	$ 11,191
Long-term debt	$ 10,000

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Asset Retirement Obligation Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Beginning asset retirement obligations	$ 5,075	$ 6,078
Liabilities incurred	165	126
Liabilities settled	(15)	(108)
Accretion expense	551	550	$ 317
Acquisitions	250
Purchase price adjustment		(1,192)
Property dispositions		(403)
Revision of estimates	(13)	24
Ending asset retirement obligations	$ 6,013	$ 5,075	$ 6,078

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Flatonia Energy, LLC [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Percentage of common stock acquired	13.30%
Payments made to related party	$ 26.6	$ 33.9
Proceeds received from related party	21.7	66.7
Amounts receivable from related party	1.5	3.9
Amounts payable to related party	$ 3.1	$ 16.4

Commitment and Contingencies -

Commitment and Contingencies - Future Minimum Contractual Commitments under Non-cancelable Agreements (Details) $ in Thousands	Dec. 31, 2016USD ($)
Operating Leased Assets [Line Items]
2,017	$ 2,381
2,018	2,304
2,019	2,270
2,020	1,647
2,021	680
Gas Contract [Member]
Operating Leased Assets [Line Items]
2,017	1,643
2,018	1,643
2,019	1,643
2,020	1,647
2,021	680
Office Leases [Member]
Operating Leased Assets [Line Items]
2,017	738
2,018	661
2,019	$ 627

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)MMBTU	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Non-cancelable fixed cost agreement, 2017	$ 2,381
Non-cancelable fixed cost agreement, 2018	2,304
Non-cancelable fixed cost agreement, 2019	2,270
Non-cancelable fixed cost agreement, 2020	1,647
Non-cancelable fixed cost agreement, 2021	680
Rent expense	800	$ 800	$ 400
Non-cancelable Agreement [Member]
Loss Contingencies [Line Items]
Non-cancelable fixed cost agreement, 2017	1,600
Non-cancelable fixed cost agreement, 2018	1,600
Non-cancelable fixed cost agreement, 2019	1,600
Non-cancelable fixed cost agreement, 2020	1,600
Non-cancelable fixed cost agreement, 2021	$ 1,600
Holding pipeline capacity | MMBTU	10,000

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
State		$ 91
Total current		91
Deferred:
Federal	$ 515	(26,214)	$ 21,803
State	13	(319)	302
Total deferred	528	(26,533)	22,105
Total income tax provision (benefit)	$ 528	$ (26,442)	$ 22,105

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Effective Tax Rate to Statutory Rate (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation Of Income Tax Rate [Line Items]
Net loss before income taxes	$ (54,013)	$ (143,097)	$ (6,729)
Tax benefit computed at statutory rate	(18,365)	(48,653)	(2,288)
Non-deductible impairment of goodwill	5,961
Non-deductible transaction costs	878
Non-taxable Oak Valley income prior to merger			(4,142)
Deferred income tax arising from change in tax status of Oak Valley			28,347
Non-deductible general and administrative expenses	5	534
Return to accrual	15	(1,398)
State income taxes, net of Federal benefit	(128)	(743)	188
Valuation allowance	12,162	23,818
Total income tax provision (benefit)	$ 528	$ (26,442)	$ 22,105
Effective tax rate	(1.00%)	18.50%	(328.50%)
U.S. [Member]
Reconciliation Of Income Tax Rate [Line Items]
Net loss before income taxes	$ (54,032)
Tax rate	34.00%
Tax benefit computed at statutory rate	$ (18,370)
Non-deductible impairment of goodwill	5,961
Non-deductible transaction costs	878
Non-deductible general and administrative expenses	5
Return to accrual	15
State income taxes, net of Federal benefit	(128)
Valuation allowance	12,167
Total income tax provision (benefit)	$ 528
Effective tax rate	(1.00%)
Canada [Member]
Reconciliation Of Income Tax Rate [Line Items]
Net loss before income taxes	$ 19
Tax rate	26.00%
Tax benefit computed at statutory rate	$ 5
Valuation allowance	$ (5)
Effective tax rate	0.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Line Items]
Income tax expense (benefit)	$ 528	$ (26,442)	$ 22,105
Valuation allowance	$ 12,162	$ 23,818
Effective tax rate	(1.00%)	18.50%	(328.50%)
Valuation allowance	$ (39,596)	$ (23,819)
Net deferred noncurrent tax assets	23,820	$ 23,819
Deferred tax liabilities	15,776
U.S. [Member]
Income Tax Disclosure [Line Items]
Income tax expense (benefit)	528
Valuation allowance	$ 12,167
Effective tax rate	(1.00%)
Deferred tax assets	$ 36,000
Deferred tax liabilities	15,800
Operating loss carryforward, net	$ 36,400
Net operating loss carryforwards expire beginning year	2,034
Net operating loss carryforwards expire ending year	2,036
Canada [Member]
Income Tax Disclosure [Line Items]
Valuation allowance	$ (5)
Effective tax rate	0.00%
Deferred tax assets	$ 3,600
Operating loss carryforward, net	$ 10,000
Net operating loss carryforwards expire beginning year	2,024
Net operating loss carryforwards expire ending year	2,036
Reminder of the Company [Member]
Income Tax Disclosure [Line Items]
Valuation allowance	$ 12,200
Lynden Arrangement [Member]
Income Tax Disclosure [Line Items]
Income tax expense (benefit)	500
Lynden Arrangement [Member] | U.S. [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforward, net	$ 28,000

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred noncurrent income tax assets (liabilities):
Office and other equipment	$ (48)	$ (253)
Oil & gas properties	7,428	23,177
Asset retirement obligation	2,042	1,788
Basis difference in subsidiary obligation	(4,226)
Intangible assets (liabilities)	36	(7)
Unrealized derivative loss (gain)	2,145	(1,284)
Stock-based compensation	1,148
Federal net operating loss carryforward	15,109	339
Other	186	59
Net deferred noncurrent tax assets	23,820	23,819
Valuation allowance	(39,596)	$ (23,819)
Net deferred tax (liability) asset	$ (15,776)

Supplemental Selected Quarter68

Supplemental Selected Quarterly Financial Data (Unaudited) - Schedule of Supplemental Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Oil and gas revenues	$ 15,152	$ 10,530	$ 9,777	$ 6,810	$ 8,231	$ 13,033	$ 14,958	$ 11,242
Loss from operations	(28,436)	(4,316)	(6,433)	(6,836)	(144,617)	(2,595)	281	(2,298)	$ (46,021)	$ (149,229)	$ (10,586)
Net loss	$ (33,048)	$ (3,900)	$ (11,172)	$ (6,421)	$ (116,511)	$ 1,718	$ (748)	$ (1,114)	$ (54,541)	$ (116,655)	$ (28,834)
Net loss per common share:
Basic and diluted net (loss) income per share	$ (1.48)	$ (0.17)	$ (0.69)	$ (0.46)	$ (8.43)	$ 0.12	$ (0.05)	$ (0.08)

Supplemental Selected Quarter69

Supplemental Selected Quarterly Financial Data (Unaudited) - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended				12 Months Ended
	Apr. 30, 2015	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Impairment expense		$ 6,800,000		$ 136,500,000		$ 24,283,000	$ 138,086,000	$ 19,359,000
Impairment of goodwill		$ 17,500,000		$ 1,600,000		17,532,000	1,547,000	$ 0
Termination of drilling rig			$ 5,100,000
Gain on sale of oil and gas properties	$ 1,600				$ 1,600,000	$ 8,000	$ 1,617,000

Supplemental Information On O70

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Costs Incurred Related to Oil and Gas Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Acquisition cost:
Proved	$ 48,116	$ 4,508	$ 74,728
Unproved	26,600	10,646	36,236
Exploration costs:
Geological and geophysical	5	142	111
Development costs	28,577	56,862	75,105
Total additions	$ 103,298	$ 72,158	$ 186,180

Supplemental Information On O71

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016USD ($)MBoeMMBoe$ / bbl$ / MMBTU	Dec. 31, 2015USD ($)MBoe$ / bbl$ / MMBTU	Dec. 31, 2014USD ($)MBoe$ / bbl$ / MMBTU	Dec. 31, 2013MBoe
Reserve Quantities [Line Items]
Additions to oil and gas properties | $	$ 103,298,000	$ 72,158,000	$ 186,180,000
Capitalized exploratory well costs | $	$ 0	$ 0	$ 0
Proved developed and undeveloped reserves increase (decrease)	(0.5)		10,800
Purchases of minerals in place	10,647	1,962	8,473
Production of minerals in place	1,465	1,437	882
Proved developed and undeveloped downward reserve revision	(10,128)	(9,484)	806
Extensions and discoveries	423	685	2,364
Proved undeveloped reserves	2,690	3,961	12,392	7,725
Estimated proved undeveloped reserves decrease	1,300
Proved developed reserves increase			6,100
Proved undeveloped reserves increase			4,700
Lynden Arrangement [Member]
Reserve Quantities [Line Items]
Purchases of minerals in place	10,647
Oak Valley Resources L L C Exchange Agreement [Member]
Reserve Quantities [Line Items]
Extensions and discoveries			2,364
Eagle Ford Property [Member]
Reserve Quantities [Line Items]
Purchases of minerals in place			8,473
Proved undeveloped reserve converted percentage	62.00%
Henry Hub Spot Price [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas | $ / MMBTU	2.48	2.59	4.30
West Texas Intermediate Spot Price [Member]
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil | $ / bbl	42.75	50.28	94.99
New Wells [Member]
Reserve Quantities [Line Items]
Additions to oil and gas properties | $	$ 200,000	$ 200,000	$ 200,000

Supplemental Information On O72

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Summary of Capitalized Costs, Impairment, and Depreciation, Depletion and Amortization (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Oil and gas properties, successful efforts method:
Accumulated impairment	$ (162,700)	$ (155,900)
Proved properties, net of accumulated impairments	363,072	283,644
Unproved properties, net of accumulated impairments	51,723	34,609
Total oil and gas properties, net of accumulated impairments	414,795	318,253
Accumulated depreciation, depletion and amortization	(145,393)	(119,920)
Net oil and gas properties	269,402	198,333
Proved Property [Member]
Oil and gas properties, successful efforts method:
Proved properties	476,832	394,532
Accumulated impairment	(113,760)	(110,888)
Proved properties, net of accumulated impairments	363,072	283,644
Unproved Property [Member]
Oil and gas properties, successful efforts method:
Unproved properties	100,612	79,619
Accumulated impairment	(48,889)	(45,010)
Unproved properties, net of accumulated impairments	$ 51,723	$ 34,609

Supplemental Information On O73

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Changes in Quantities of Proved Oil and natural Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf
Reserve Quantities [Line Items]
Beginning balance | MBoe	12,574	22,192	11,431
Extensions and discoveries | MBoe	423	685	2,364
Sales of minerals in place | MBoe		(1,344)
Purchases of minerals in place | MBoe	10,647	1,962	8,473
Production | MBoe	(1,465)	(1,437)	(882)
Revision to previous estimates | MBoe	(10,128)	(9,484)	806
Ending Balance | MBoe	12,051	12,574	22,192
Proved developed reserves | MBoe	9,361	8,613	9,800	3,706
Proved undeveloped reserves | MBoe	2,690	3,961	12,392	7,725
Crude Oil [Member]
Reserve Quantities [Line Items]
Beginning balance	9,361	13,803	6,078
Extensions and discoveries	345	526	1,909
Sales of minerals in place		(4)
Purchases of minerals in place	5,548	1,641	7,025
Production	(878)	(904)	(403)
Revision to previous estimates	(7,265)	(5,701)	(806)
Ending balance	7,111	9,361	13,803
Proved developed reserves	6,052	6,114	6,093	1,307
Proved undeveloped reserves	1,059	3,247	7,710	4,771
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance | MMcf	13,338	38,579	24,213
Extensions and discoveries | MMcf	285	828	1,403
Sales of minerals in place | MMcf		(8,040)
Purchases of minerals in place | MMcf	14,770	679	6,064
Production | MMcf	(2,171)	(2,143)	(2,132)
Revision to previous estimates | MMcf	(5,821)	(16,565)	9,031
Ending Balance | MMcf	20,401	13,338	38,579
Proved developed reserves | MMcf	13,545	10,954	16,214	11,053
Proved undeveloped reserves | MMcf	6,856	2,384	22,365	13,160
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning balance	990	1,959	1,318
Extensions and discoveries	30	21	221
Purchases of minerals in place	2,637	208	437
Production	(225)	(176)	(124)
Revision to previous estimates	(1,892)	(1,022)	107
Ending balance	1,540	990	1,959
Proved developed reserves	1,051	673	1,005	557
Proved undeveloped reserves	489	317	954	761

Supplemental Information On O74

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule of Changes in Proved Undeveloped Reserves (Details)	12 Months Ended
	Dec. 31, 2016MBoe
Extractive Industries [Abstract]
Proved undeveloped reserves at December 31, 2015	3,961
Conversions to developed	(169)
Extensions and discoveries	293
Purchases	873
Revisions	(2,268)
Proved undeveloped reserves at December 31, 2016	2,690

Supplemental Information On O75

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule Of Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash inflows	$ 346,948	$ 481,131	$ 1,464,138
Future production costs	(172,062)	(192,349)	(427,113)
Future development costs	(29,814)	(91,725)	(312,010)
Future income tax expense			(180,248)
Future net cash flows	145,072	197,057	544,767
10% annual discount for estimated timing of cash flows	(59,189)	(92,661)	(288,911)
Standardized measure of discounted future cash flows	$ 85,883	$ 104,396	$ 255,856	$ 125,357

Supplemental Information On O76

Supplemental Information On Oil And Gas Exploration And Production Activities - Schedule Of Changes In Standardized Measure Of Discontinued Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Standardized Measure, beginning of year	$ 104,396	$ 255,856	$ 125,357
Sales of oil and gas produced, net of production costs	(24,998)	(29,152)	(35,794)
Sales of minerals in place		(2,470)
Net changes in prices and production costs	(102,143)	(288,064)	(34,681)
Extensions, discoveries, and improved recoveries	241	6,514	54,157
Changes in income taxes, net		88,944	(88,944)
Previously estimated development costs incurred during the period	27,770	26,977	18,252
Net changes in future development costs	102,267	6,697	7,028
Purchases of minerals in place	16,921	7,695	163,309
Revisions of previous quantity estimates	(45,239)	(16,671)	16,283
Accretion of discount	11,506	25,586	12,536
Changes in timing of estimated cash flows and other	(4,838)	22,484	18,353
Standardized Measure, end of year	$ 85,883	$ 104,396	$ 255,856