Earthstone Energy (ESTE) 10-K 10 Mar 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2020	Mar. 04, 2021	Jun. 30, 2020
Document And Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-35049
Entity Registrant Name	EARTHSTONE ENERGY, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	84-0592823
Entity Address, Address Line One	1400 Woodloch Forest Drive
Entity Address, Address Line Two	Suite 300
Entity Address, City or Town	The Woodlands
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77380
City Area Code	281
Local Phone Number	298-4246
Title of 12(b) Security	Class A Common Stock, $0.001 par value per share
Trading Symbol	ESTE
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 64,727,959
Documents Incorporated by Reference	Portions of the Registrant’s Definitive Proxy Statement for its 2021 Annual Meeting of Stockholders (the “Proxy Statement”), are incorporated by reference into Part III of this Annual Report on Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0000010254
Class A Common Stock
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		43,646,391
Class B Common Stock
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		34,443,898

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash	$ 1,494	$ 13,822
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	16,255	29,047
Joint interest billings and other, net of allowance of $19 and $83 at December 31, 2020 and 2019, respectively	7,966	6,672
Derivative asset	7,509	8,860
Prepaid expenses and other current assets	1,509	1,867
Total current assets	34,733	60,268
Oil and gas properties, successful efforts method:
Proved properties	1,017,496	970,808
Unproved properties	233,767	260,271
Land	5,382	5,382
Total oil and gas properties	1,256,645	1,236,461
Accumulated depreciation, depletion and amortization	(291,213)	(195,567)
Net oil and gas properties	965,432	1,040,894
Other noncurrent assets:
Goodwill	0	17,620
Office and other equipment, net of accumulated depreciation of $3,675 and $3,180 at December 31, 2020 and 2019, respectively	931	1,311
Derivative asset	396	770
Operating lease right-of-use assets	2,450	3,108
Other noncurrent assets	1,315	1,572
TOTAL ASSETS	1,005,257	1,125,543
Current liabilities:
Accounts payable	6,232	25,284
Revenues and royalties payable	27,492	35,815
Accrued expenses	16,504	19,538
Asset retirement obligation	447	308
Derivative liability	1,135	6,889
Advances	2,277	11,505
Operating lease liability	773	570
Finance lease liability	69	206
Other current liabilities	565	43
Total current liabilities	55,494	100,158
Noncurrent liabilities:
Long-term debt	115,000	170,000
Asset retirement obligation	2,580	1,856
Derivative liability	173	0
Deferred tax liability	14,497	15,154
Operating lease liability	1,840	2,539
Finance lease liability	5	85
Other noncurrent liabilities	132	0
Total noncurrent liabilities	134,227	189,634
Commitments and Contingencies (Note 16)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding	0	0
Additional paid-in capital	540,074	527,246
Accumulated deficit	(195,258)	(181,711)
Total Earthstone Energy, Inc. equity	344,881	345,599
Noncontrolling interest	470,655	490,152
Total equity	815,536	835,751
TOTAL LIABILITIES AND EQUITY	1,005,257	1,125,543
Class A Common Stock
Equity:
Common stock	30	29
Class B Common Stock
Equity:
Common stock	$ 35	$ 35

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Joint interest billings and other, allowance	$ 19	$ 83
Office and other equipment, accumulated depreciation	$ 3,675	$ 3,180
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)	20,000,000	20,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Class A Common Stock
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	200,000,000	200,000,000
Common stock, shares issued (in shares)	30,343,421	29,421,131
Common stock, shares outstanding (in shares)	30,343,421	29,421,131
Class B Common Stock
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	50,000,000	50,000,000
Common stock, shares issued (in shares)	35,009,371	35,260,680
Common stock, shares outstanding (in shares)	35,009,371	35,260,680

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
REVENUES
Revenues	$ 144,523	$ 191,262
OPERATING COSTS AND EXPENSES
Lease operating expense	29,131	28,683
Production and ad valorem taxes	9,411	11,871
Rig idle and termination expense	426	0
Impairment expense	64,498	0
Depreciation, depletion and amortization	96,414	69,243
General and administrative expense	28,233	27,611
Transaction costs	622	1,077
Accretion of asset retirement obligation	307	214
Exploration expense	298	653
Total operating costs and expenses	229,340	139,352
Gain on sale of oil and gas properties, net	204	3,222
(Loss) income from operations	(84,613)	55,132
OTHER INCOME (EXPENSE)
Interest expense, net	(5,232)	(6,566)
Write-off of deferred financing costs	0	(1,242)
Gain (loss) on derivative contracts, net	59,899	(43,983)
Other income (expense), net	400	(96)
Total other income (expense)	55,067	(51,887)
(Loss) income before income taxes	(29,546)	3,245
Income tax benefit (expense)	112	(1,665)
Net (loss) income	(29,434)	1,580
Less:  Net (loss) income attributable to noncontrolling interest	(15,887)	861
Net (loss) income attributable to Earthstone Energy, Inc.	$ (13,547)	$ 719
Net (loss) income per common share attributable to Earthstone Energy, Inc.:
Basic (in dollars per share)	$ (0.45)	$ 0.02
Diluted (in dollars per share)	$ (0.45)	$ 0.02
Weighted average common shares outstanding:
Basic (in shares)	29,911,625	28,983,354
Diluted (in shares)	29,911,625	29,360,885
Oil Revenue
REVENUES
Revenues	$ 120,355	$ 171,925
Natural Gas (MMcf)
REVENUES
Revenues	8,567	3,913
NGLs (MBbl)
REVENUES
Revenues	$ 15,601	$ 15,424

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Cumulative Effect, Period of Adoption, Adjustment	Restricted Stock Units	Class B Common Stock	Common StockClass A Common Stock	Common StockClass A Common StockRestricted Stock Units	Common StockClass B Common Stock	Additional Paid-in Capital	Additional Paid-in CapitalRestricted Stock Units	Accumulated Deficit	Accumulated DeficitCumulative Effect, Period of Adoption, Adjustment	Earthstone Energy, Inc. Equity	Earthstone Energy, Inc. EquityCumulative Effect, Period of Adoption, Adjustment	Noncontrolling Interest	Noncontrolling InterestCumulative Effect, Period of Adoption, Adjustment
Increase (Decrease) in Stockholders' Equity [Roll Forward]
ASC 842 implementation	$ 826,492	$ 166			$ 29		$ 35	$ 517,073		$ (182,497)	$ 67	$ 334,640	$ 67	$ 491,852	$ 99
Beginning Balance (shares) at Dec. 31, 2018					28,696,321		35,452,178
Beginning Balance at Dec. 31, 2018	826,492	166			$ 29		$ 35	517,073		(182,497)	67	334,640	67	491,852	99
Increase (Decrease) in Stockholders' Equity [Roll Forward]
ASC 842 implementation	$ 826,492	$ 166			$ 29		$ 35	527,246		(181,711)	$ 67	345,599	$ 67	490,152	$ 99
Accounting Standards Update [Extensible List]	us-gaap:AccountingStandardsUpdate201801Member
Stock-based compensation expense	$ 8,648							8,648				8,648
Vesting of restricted stock units, net of taxes paid (in shares)						(533,312)
Class A common and vested restricted stock retained by the company in exchange for payment of recipient mandatory tax withholdings (in shares)					203,394
Class A common and vested restricted stock retained by the company in exchange for payment of recipient mandatory tax withholdings	(1,135)							(1,135)				(1,135)
Cancellation of treasury shares (in shares)					(203,394)
Class B Common Stock converted to Class A Common Stock (in shares)				191,498	191,498		(191,498)
Class B Common Stock converted to Class A Common Stock	0							2,660				2,660		(2,660)
Net income	1,580									719		719		861
Ending Balance (shares) at Dec. 31, 2019					29,421,131		35,260,680
Ending Balance at Dec. 31, 2019	835,751				$ 29		$ 35	527,246		(181,711)		345,599		490,152
Increase (Decrease) in Stockholders' Equity [Roll Forward]
ASC 842 implementation	835,751				29		35	527,246		(181,711)		345,599		490,152
ASC 842 implementation	835,751				$ 30		$ 35	540,074		(195,258)		344,881		470,655
Stock-based compensation expense	10,054							10,054				10,054
Vesting of restricted stock units, net of taxes paid (in shares)						670,981
Vesting of restricted stock units, net of taxes paid			$ 0			$ 1			$ (1)
Class A common and vested restricted stock retained by the company in exchange for payment of recipient mandatory tax withholdings (in shares)					243,924
Class A common and vested restricted stock retained by the company in exchange for payment of recipient mandatory tax withholdings	(835)							(835)				(835)
Cancellation of treasury shares (in shares)					(243,924)
Class B Common Stock converted to Class A Common Stock (in shares)				251,309	251,309		(251,309)
Class B Common Stock converted to Class A Common Stock	0							3,610				3,610		(3,610)
Net income	(29,434)									(13,547)		(13,547)		(15,887)
Ending Balance at Dec. 31, 2020	815,536				$ 30		$ 35	540,074		(195,258)		344,881		470,655
Increase (Decrease) in Stockholders' Equity [Roll Forward]
ASC 842 implementation	$ 815,536				$ 30		$ 35	$ 540,074		$ (195,258)		$ 344,881		$ 470,655

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net (loss) income	$ (29,434,000)	$ 1,580,000
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties	46,878,000	0
Depreciation, depletion and amortization	96,414,000	69,243,000
Accretion of asset retirement obligation	307,000	214,000
Impairment of goodwill	17,620,000	0
Gain on sale of oil and gas properties, net	(204,000)	(3,222,000)
Settlement of asset retirement obligations	(195,000)	(374,000)
Total (gain) loss on derivative contracts, net	(59,899,000)	43,983,000
Operating portion of net cash received in settlement of derivative contracts	56,044,000	15,866,000
Stock-based compensation	10,054,000	8,648,000
Deferred income taxes	(657,000)	1,665,000
Write-off of deferred financing costs	0	1,242,000
Amortization of deferred financing costs	322,000	412,000
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	11,914,000	(18,035,000)
(Increase) decrease in prepaid expenses and other current assets	(203,000)	66,000
Increase (decrease) in accounts payable and accrued expenses	481,000	(10,438,000)
Increase (decrease) in revenues and royalties payable	(8,323,000)	7,067,000
Increase (decrease) in advances	(9,617,000)	8,331,000
Net cash provided by operating activities	131,502,000	126,248,000
Cash flows from investing activities:
Additions to oil and gas properties	(88,097,000)	(204,268,000)
Additions to office and other equipment	(114,000)	(527,000)
Proceeds from sale of oil and gas properties	414,000	4,184,000
Net cash used in investing activities	(87,797,000)	(200,611,000)
Cash flows from financing activities:
Proceeds from borrowings	136,056,000	234,680,000
Repayments of borrowings	(191,056,000)	(143,508,000)
Cash paid related to the exchange and cancellation of Class A Common Stock	(836,000)	(1,135,000)
Cash paid for finance leases	(130,000)	(392,000)
Deferred financing costs	(67,000)	(1,836,000)
Net cash (used in) provided by financing activities	(56,033,000)	87,809,000
Net increase (decrease) in cash	(12,328,000)	13,446,000
Cash at beginning of period	13,822,000	376,000
Cash at end of period	1,494,000	13,822,000
Cash paid for:
Interest	4,588,000	6,405,000
Non-cash investing and financing activities:
Accrued capital expenditures	7,328,000	28,356,000
Lease asset additions - ASC 842	0	3,722,000
Asset retirement obligations	$ 762,000	$ 105,000

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	Organization and Basis of Presentation Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with its consolidated subsidiaries, the “Company”), is a growth-oriented independent oil and natural gas development and production company. In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities. The Company’s operations are all in the up-stream segment of the oil and natural gas industry and all its properties are onshore in the United States. Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc., a Utah corporation (“Lynden US”) and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH’s members other than Earthstone and Lynden US.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation The Consolidated Financial Statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation. Use of Estimates The preparation of the Company’s Consolidated Financial Statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods then ended. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of the Company’s estimates. All reserve data used in the preparation of the Consolidated Financial Statements, as well as included in Note 21. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) , 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, valuation of derivative instruments and valuation of certain performance-based restricted stock unit awards. 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 Note 21. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) . Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting. Accounts Receivable Accounts receivable include estimated 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. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. 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 $0.02 million and $0.1 million at December 31, 2020 and 2019, respectively. Derivative Instruments The Company utilizes derivative instruments in order to manage exposure to risks associated with fluctuating commodity prices and interest rates. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are mark-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in Gain (loss) on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in Gain (loss) on derivative contracts, net in the Consolidated Statements of Operations. Oil and Natural Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties. For more information see Note 7. 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 indicate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors. A discounted future cash flow analysis of the properties to which the Goodwill was associated was performed based on commodity price futures as of March 31, 2020. The resulting fair value was lower than the net book value of the associated properties. Additionally, the Company’s enterprise value, calculated as the combined market capitalization of the Company’s equity and long-term debt, was lower than the book value of its assets, without allocating between the Company's two major properties, Midland properties and Eagle Ford properties. Accordingly, the entire $17.6 million balance of Goodwill was impaired on that date, resulting in no remaining amounts subject to impairment. There were no impairments to Goodwill recorded in the year ended December 31, 2019. For further discussion, see Note 8. Goodwill . Office and Other Equipment Office and other equipment primarily includes leasehold improvements, vehicles, computer equipment and software, office furniture and fixtures and field equipment. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two years to 10 years. The Company had office and other equipment of $0.9 million and $1.3 million, net of accumulated depreciation and amortization of $3.7 million and $3.2 million, at December 31, 2020 and 2019, respectively. During the years ended December 31, 2020 and 2019, the Company recognized depreciation expense of $0.5 million and $0.7 million, respectively. See separate finance lease disclosures in Note 19. Leases . Noncontrolling Interest Noncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2020 and 2019, as well as an adjustment to Net income in the Consolidated Statement of Operations for the years ended December 31, 2020 and 2019. As of December 31, 2020, Earthstone and Lynden US owned a 46.4% membership interest in EEH while Bold Energy Holdings, LLC (“Bold Holdings”), the noncontrolling third-party, owned the remaining 53.6%. See further discussion in Note 9. Noncontrolling Interest . Segment Reporting Operating segments are components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on the Company’s organization and management, it has only one reportable operating segment, which is oil and natural gas exploration and production. Comprehensive Income The Company has no elements of comprehensive income other than net income. 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 14. Asset Retirement Obligations . Business Combinations The Company accounts for its acquisitions of oil and gas properties not commonly controlled in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, which, among other things, requires the Company to determine if an asset or a business has been acquired. If the Company determines an asset(s) has been acquired, the asset(s) acquired, as well as any liabilities assumed, are measured and recorded at the acquisition date cost. If the Company determines a business has been acquired, the assets acquired and liabilities assumed are measured and recorded at their fair values as of the acquisition date, recording goodwill for amounts paid in excess of fair value. Revenue Recognition The Company’s revenues are comprised solely of revenues from customers and include the sale of oil, natural gas and natural gas liquids. The Company believes that the disaggregation of revenue into these three major product types, as presented in the Consolidated Statements of Operations, appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic region. Revenues are recognized when the recognition criteria of ASC 606 “Revenue from Contracts with Customers,” (“ASC 606”) are met, which generally occurs at a point in time when production is sold to a purchaser at a determinable price, delivery has occurred, control has transferred and collection of the revenue is probable . The Company fulfills its performance obligations under its customer contracts through delivery of oil, natural gas and natural gas liquids and revenues are recorded on a monthly basis and the Company receives payment from one to three months after delivery. Generally, each unit of product represents a separate performance obligation. The prices received for oil, natural gas and natural gas liquids sales under the Company’s contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, revenues from the sale of oil, natural gas and natural gas liquids will decrease if market prices decline. The sales of oil, natural gas and natural gas liquids, as presented on the Consolidated Statements of Operations, represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil, natural gas and natural gas liquids on behalf of royalty or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are recorded in “Accounts receivable: oil, natural gas, and natural gas liquids revenues” in the Consolidated Balance Sheets. As of December 31, 2020 and 2019 , amounts receivable from contracts with customers were $16.3 million and $29.0 million, respectively. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues in the Consolidated Statements of Operations. Oil Sales Oil production is transported from the wellhead to tank batteries or delivery points through flow-lines or gathering systems. Purchasers of the oil take delivery at (i) the tank batteries and transport the oil by truck, or (ii) at a pipeline delivery point and the Company collects a market price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the net price received by the Company. Starting in October 2019, certain of the Company’s oil sales activity involves buy/sell arrangements that effect a change in location with required repurchase of oil at a delivery point. Because the Company acts as the agent in these transactions, the buy/sell activity is recorded on a net basis and the residual transportation fee is included in Lease operating expenses in the Consolidated Statements of Operations. Natural Gas and NGL Sales Under the Company’s natural gas sales arrangements, the purchaser takes control of wet gas at a delivery point near the wellhead or at the inlet of the purchaser’s processing facility. The purchaser gathers and processes the wet gas and remits proceeds to the Company for the resulting natural gas and NGL sales. Based on the nature of these arrangements, the Company is the agent and the purchaser is the Company’s customer, thus, the Company recognizes natural gas and NGL sales based on the net amount of proceeds received from the purchaser. Imbalances The Company recognizes revenue for all oil, natural gas and NGL sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company had no imbalances as of December 31, 2020 or 2019. Contract Balances Under the Company’s product sales contracts, the Company invoices customers once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. Transaction Price Allocated to Remaining Performance Obligations Substantially all of the Company’s product sales are short-term in nature, with a contract term of one year or less. For these contracts, the Company has utilized the practical expedient in ASC 606 which exempts the Company from the requirements to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Prior-Period Performance Obligations The Company records revenue in the month that product is delivered to the purchaser. Settlement statements for certain natural gas and NGLs sales, however, may not be received for 30 to 90 days after the date the product is delivered, and as a result the Company is required to estimate the amount of product delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For the years ended December 31, 2020 and 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. 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 the year ended December 31, 2020, three purchasers accounted for 32%, 15% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In the year ended December 31, 2019, three purchasers accounted for 30%, 14% and 12%, 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 the years ended December 31, 2020 and 2019. Additionally, at December 31, 2020, three purchasers accounted for 18%, 17% and 16%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. At December 31, 2019, three purchasers accounted for 46%, 14% and 10%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2020 or 2019. The Company holds working interests in oil and natural gas properties for which a third-party serves as operator. The operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In the year ended December 31, 2020, one operator distributed 15% of the Company’s oil, natural gas and natural gas liquids revenues. In the year ended December 31, 2019, no operator distributed 10% or more 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, 2020, the Company had a net derivative asset position of $6.6 million. At December 31, 2019, the Company had $2.7 million of derivative contracts that were in a material asset position. The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage. Stock-Based Compensation The Company recognized stock-based compensation expense associated with restricted stock units, which include both time- and performance-based awards. The Company accounts for forfeitures of equity-based incentive awards as they occur. Stock-based compensation expense related to time-based restricted stock units is based on the price of the Class A common stock, $0.001 par value per share of Earthstone (“Class A Common Stock”), on the grant date and recognized over the vesting period using the straight-line method. Stock-based compensation expense related to performance-based restricted stock units, which cliff vest, is based on a grant date Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes fair value based on the most likely outcome, and is recognized over the vesting period using the straight-line method. See Note 12. Stock-Based Compensation for further details. Income Taxes The Company is a U.S. company operating in Texas, as of December 31, 2020, as well as one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which its operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the Consolidated Financial Statements, the Company is required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as its operations are conducted in different taxing jurisdictions. The Company records an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from Earthstone’s acquisition of Lynden Corp in May 2016 (the “Lynden Arrangement”) that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax. The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in the Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2020 and 2019, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets. The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. It requires that the Company recognize in the Consolidated Financial Statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management and they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2020 or 2019. Recently Issued Accounting Standards Intangibles – Goodwill and Other – In January 2017, the FASB issued updated guidance simplifying the test for goodwill impairment. The update eliminates the requirement to determine the implied value of goodwill in measuring an impairment loss. Upon adoption, the measurement of a goodwill impairment will represent the excess of the reporting unit’s carrying value over its fair value and will be limited to the carrying value of goodwill. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The update is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements. See further discussion of goodwill in Note 8. Goodwill . Fair Value Measurements – In August 2018, the FASB issued an update which modifies the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements. Income Taxes - In December 2019, the FASB issued an update that simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020 and early adoption is permitted. The Company adopted the update effective January 1, 2021 and the impact was not material to the Consolidated Financial Statements. Credit Losses - In June 2016, the FASB issued an update that requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance is effective for interim and annual periods beginning after December 15, 2019. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements. Reference Rate Reform - In March 2020, the FASB issued an update that provides optional guidance for a limited period of time to ease the transition from LIBOR to an alternative reference rate. The ASU intends to address certain concerns relating to accounting for contract modifications and hedge accounting. These optional expedients and exceptions to applying GAAP, assuming certain criteria are met, are allowed through December 31, 2022. The Company is currently evaluating the provisions of this update and has not yet determined whether it will elect the optional expedients. The Company does not expect the transition to an alternative rate to have a material impact on its business, operations or liquidity.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures The initial accounting for acquisitions and divestitures may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about the facts and circumstances that existed as of the acquisition dates. Midland Basin Acquisition On January 7, 2021, the Company completed an acquisition as described in Note 20. Subsequent Event . Divestitures

Transaction Costs

Transaction Costs	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Transaction Costs	Transaction CostsDuring the year ended December 31, 2020, the Company recorded transaction costs primarily due to legal, consulting and other fees of approximately $1.0 million related to the acquisition noted above and $0.3 million related to other potential transactions, offset by net reimbursements of $0.7 million related to the business combination (the “Bold Transaction”) pursuant to the Bold Contribution Agreement (as defined below) which closed on May 9, 2017.During the year ended December 31, 2019, the Company recorded transaction costs totaling approximately $1.1 million primarily due to the Bold Transaction.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements FASB ASC Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets. The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows: Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the year ended December 31, 2020. 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 and interest rate swaps. The Company’s commodity price hedges and interest rate swaps are valued based on discounted future cash flow models that are primarily based on published forward commodity price curves and published LIBOR forward curves; thus, these inputs are designated as Level 2 within the valuation hierarchy. The fair values of derivative instruments in asset positions include measures of counterparty nonperformance risk, and the fair values of derivative instruments in liability positions include measures 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, 2020 Level 1 Level 2 Level 3 Total Financial assets Derivative asset- current $ — $ 7,509 $ — $ 7,509 Derivative asset- noncurrent — 396 — 396 Total financial assets $ — $ 7,905 $ — $ 7,905 Financial liabilities Derivative liability - current $ — $ 1,135 $ — $ 1,135 Derivative liability - noncurrent — 173 — 173 Total financial liabilities $ — $ 1,308 $ — $ 1,308 December 31, 2019 Financial assets Derivative asset- current $ — $ 8,860 $ — $ 8,860 Derivative asset- noncurrent — 770 — 770 Total financial assets $ — $ 9,630 $ — $ 9,630 Financial liabilities Derivative liability - current $ — $ 6,889 $ — $ 6,889 Derivative liability - noncurrent — — — — Total financial liabilities $ — $ 6,889 $ — $ 6,889 Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal. Fair Value on a Nonrecurring Basis The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and goodwill. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. Proved Oil and Natural Gas Properties Proved oil and natural gas properties are reviewed for impairment on a nonrecurring basis. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets. See Note 7. Oil and Natural Gas Properties. Performance Units Among other things, the Earthstone Amended and Restated 2014 Long-Term Incentive Plan (the “2014 Plan”) allows for the grant of performance units. The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. See Note 12. Stock-Based Compensation. Goodwill Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the fair value of goodwill may be less than its carrying amount. Such test includes an assessment of qualitative and quantitative factors. See Note 8. Goodwill . Business Combinations The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 3. Acquisitions and Divestitures . Asset Retirement Obligations The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. See Note 14. Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments Commodity Derivative Instruments The Company’s hedging activities consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swaps and basis swaps agreements. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Consistent with its hedging policy, the Company has entered into a series of derivative instruments to hedge a significant portion of its expected oil and natural gas production through December 31, 2021. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, the Company believes these instruments reduce its exposure to oil and natural gas price fluctuations and, thereby, allow the Company to achieve a more predictable cash flow. The Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow related to a forecasted transaction. The Company does not enter into derivative instruments for trading or other speculative purposes. These transactions are recorded in the Consolidated Financial Statements in accordance with FASB ASC Topic 815. The Company has accounted for these transactions using the mark-to-market accounting method. Generally, the Company incurs accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in the Consolidated Balance Sheets and Consolidated Statements of Operations. The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The following table sets forth the Company’s outstanding derivative contracts at December 31, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed. Period Commodity Volume Price 2021 Crude Oil Swap 2,294,000 $51.17 2021 Crude Oil Basis Swap (1) 1,825,000 $1.05 2022 Crude Oil Swap 365,000 $47.70 2021 Natural Gas Swap 4,380,000 $2.76 2021 Natural Gas Basis Swap (2) 4,380,000 $(0.45) (1) The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX. (2) The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX. 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, 2020 December 31, 2019 Derivatives not Balance Sheet Location Gross Gross Net Gross Gross Net Commodity contracts Derivative asset - current $ 11,071 $ (3,562) $ 7,509 $ 13,321 $ (4,461) $ 8,860 Commodity contracts Derivative liability - current $ 4,492 $ (3,562) $ 930 $ 11,350 $ (4,461) $ 6,889 Interest rate swaps Derivative liability - current $ 205 $ — $ 205 $ — $ — $ — Commodity contracts Derivative asset - noncurrent $ 396 $ — $ 396 $ 1,031 $ (261) $ 770 Commodity contracts Derivative liability - noncurrent $ — $ — $ — $ 261 $ (261) $ — Interest rate swaps Derivative liability - noncurrent $ 173 $ — $ 173 $ — $ — $ — 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 and Consolidated Statements of Cash Flows (in thousands) : Derivatives not designated as hedging contracts under ASC Topic 815 Years Ended December 31, Statement of Cash Flows Location Statement of Operations Location 2020 2019 Unrealized gain (loss) Not presented separately Not presented separately $ 3,855 $ (59,849) Realized gain Operating portion of net cash received in settlement of derivative contracts Not presented separately 56,044 15,866 Total (gain) loss on derivative contracts, net Gain (loss) on derivative contracts, net $ 59,899 $ (43,983)

Oil and Natural Gas Properties

Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, costs to acquire oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale or retirement of oil and natural gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized. Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Gains and losses arising from the sale of properties are included in operating income in the Consolidated Statements of Operations. The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. Depletion expense for oil and natural gas producing property and related equipment was $95.9 million and $68.5 million for the years ended December 31, 2020 and 2019, respectively. Proved Oil and Natural Gas Properties Proved oil and natural gas properties are reviewed for impairment on a nonrecurring basis. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets. Unproved Oil and Natural Gas Properties Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and natural gas leases are generally for a primary term of three The Company reviews its unproved properties periodically for impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, the Company’s geologists’ evaluation of the property, and the remaining months in the lease term for the property. Impairments to Oil and Natural Gas Properties During the year ended December 31, 2020, primarily as a result of the decline in crude oil price futures, the Company recorded non-cash impairment charges of $25.3 million to its proved oil and natural gas properties and $13.2 million to its unproved oil and natural gas properties, located in the Eagle Ford Trend. As a result of certain acreage expirations, the Company recorded non-cash impairment charges of $8.4 million to its unproved oil and natural gas properties during the year ended December 31, 2020. The Company recorded no non-cash asset impairment charges for the year ended December 31, 2019. Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, 2020 and 2019 were $168.0 million and $121.1 million, respectively.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets. The fair value of Goodwill is classified as a Level 3 measurement according to the fair value hierarchy defined by ASC 820. Goodwill 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. If the results of such tests are such that the fair value of the reporting unit is less than the carrying value, goodwill is then reduced by an amount that is equal to the amount by which the carrying value exceeds the fair value. A discounted future cash flow analysis of the properties to which the Goodwill was associated was performed based on commodity price futures as of March 31, 2020. The resulting fair value was lower than the net book value of the associated properties. Additionally, the Company’s enterprise value, calculated as the combined market capitalization of the Company’s equity and long-term debt, was lower than the book value of its assets, without allocating between the Company's two major properties, Midland properties and Eagle Ford properties. Accordingly, the entire $17.6 million balance of Goodwill was impaired on that date, resulting in no remaining amounts subject to impairment. The goodwill impairment charge is included in Impairment expense in the Consolidated Statement of Operations for the year ended December 31, 2020. The Company did not have any non-cash impairment charges to Goodwill for the year ended December 31, 2019. Accumulated impairments to Goodwill as of December 31, 2020 and 2019 were $36.7 million and $19.1 million, respectively.

Noncontrolling Interest

Noncontrolling Interest	12 Months Ended
	Dec. 31, 2020
Noncontrolling Interest [Abstract]
Noncontrolling Interest	Noncontrolling Interest Earthstone consolidates the financial results of EEH and its subsidiaries, and records a noncontrolling interest for the economic interest in Earthstone held by the members of EEH other than Earthstone and Lynden US. Net income attributable to noncontrolling interest in the Consolidated Statements of Operations for the year ended December 31, 2020 represents the portion of net income attributable to the economic interest in the Company held by the members of EEH other than Earthstone and Lynden US. Noncontrolling interest in the Consolidated Balance Sheet as of December 31, 2020 represents the portion of net assets of the Company attributable to the members of EEH other than Earthstone and Lynden US. The following table presents the changes in noncontrolling interest for the year ended December 31, 2020: EEH Units Held By Earthstone and Lynden US % EEH Units Held By Others % Total EEH Units Outstanding As of December 31, 2019 29,421,131 45.5 % 35,260,680 54.5 % 64,681,811 EEH Units issued in connection with the vesting of restricted stock units 670,981 — 670,981 EEH Units and Class B Common Stock converted to Class A Common Stock 251,309 (251,309) — As of December 31, 2020 30,343,421 46.4 % 35,009,371 53.6 % 65,352,792

Net Income (Loss) Per Common Sh

Net Income (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Net Income (Loss) Per Common Share	Net (Loss) Income Per Common Share Net (loss) income per common share—basic is calculated by dividing Net (loss) income by the weighted average number of shares of common stock outstanding during the period. Net (loss) income per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net (loss) income by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net (loss) income per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect. A reconciliation of Net (loss) income per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2020 2019 Net (loss) income attributable to Earthstone Energy, Inc. $ (13,547) $ 719 Net (loss) income per common share attributable to Earthstone Energy, Inc.: Basic $ (0.45) $ 0.02 Diluted $ (0.45) $ 0.02 Weighted average common shares outstanding Basic 29,911,625 28,983,354 Add potentially dilutive securities: Unvested restricted stock units — — Unvested performance units — 377,531 Diluted weighted average common shares outstanding 29,911,625 29,360,885

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Common Stock	Common Stock Class A Common Stock At December 31, 2020 and 2019, there were 30,343,421 and 29,421,131 shares of Class A Common Stock issued and outstanding, respectively. During the years ended December 31, 2020 and 2019, as a result of the vesting and settlement of restricted stock units under the 2014 Plan, Earthstone issued 914,905 and 736,706 shares of Class A Common Stock, respectively, of which 243,924 and 203,394 shares of Class A Common Stock, respectively, were retained as treasury stock and canceled to satisfy the related employee income tax liability. Class B Common Stock

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	Stock-Based Compensation Restricted Stock Units The 2014 Plan allows, among other things, for the grant of restricted stock units (“RSUs”). As of December 31, 2020, the maximum number of shares of Class A Common Stock that may be issued under the 2014 Plan was 9.4 million shares. Each RSU represents the contingent right to receive one share of Class A Common Stock. The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting and settlement. The Company determines the fair value of granted RSUs based on the market price of the Class A Common Stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting term and is net of forfeitures, as incurred. Stock-based compensation is included in General and administrative expense in the Consolidated Statements of Operations and is recorded with a corresponding increase in Additional paid-in capital within the Consolidated Balance Sheets. The table below summarizes unvested RSU activity for the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value Unvested RSUs at December 31, 2019 1,107,796 $ 6.60 Granted 859,100 $ 5.07 Forfeited (1,083) $ 5.19 Vested (914,905) $ 6.37 Unvested RSUs at December 31, 2020 1,050,908 $ 5.55 During the year ended December 31, 2020, Earthstone granted 744,700 RSUs to employees and 114,400 RSUs to certain members of the Board with vesting periods ranging from 12 to 36 months. The total grant date fair value of the RSUs granted during the years ended December 31, 2020 and 2019 were $4.4 million and $6.5 million, respectively, with a weighted average grant date fair value per share of $5.07 and $6.04, respectively. The total vesting date fair value of the RSUs that vested during 2020 and 2019 was $3.0 million and $4.2 million, respectively. As of December 31, 2020, there was approximately $5.7 million of total unrecognized stock-based compensation expense related to unvested RSUs, which will be amortized over the remaining vesting periods. The weighted average remaining vesting period of the unrecognized compensation expense is 0.98 years. For the years ended December 31, 2020 and 2019, stock-based compensation related to RSUs was $5.4 million and $5.9 million, respectively. Performance Units The table below summarizes performance unit (“PSU”) activity for the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value Unvested PSUs at December 31, 2019 835,625 $ 10.51 Granted 1,043,800 $ 5.36 Unvested PSUs at December 31, 2020 1,879,425 $ 7.65 On January 30, 2020, the Board of Directors of Earthstone (the “Board”) granted 1,043,800 PSUs (the “2020 PSUs”) to certain officers pursuant to the 2014 Plan (the “2020 Grant”). The 2020 Grant was subject to the approval of an amendment to the 2014 Plan to increase the number of available shares available thereunder (the “2014 Plan Amendment”). The 2014 Plan Amendment was approved at the 2020 annual meeting of stockholders held on June 3, 2020. The 2020 PSUs are payable in shares of Class A Common Stock based upon the achievement by the Company over a period commencing on February 1, 2020 and ending on January 31, 2023 (the “Performance Period”) of certain performance criteria established by the Board. The 2020 PSUs are eligible to be earned based on the annualized Total Shareholder Return (“TSR”) of the Class A Common Stock during a three-year period beginning on February 1, 2020. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals: Earthstone’s Annualized TSR TSR Multiplier 23.9% or greater 2.0 14.5% 1.0 8.4% 0.5 Less than 8.4% 0.0 In the event that greater than 1.0x of the 2020 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock. Based on the COVID-19 pandemic and the recent commodity price crash, the Company believes that the target annualized TSR of 14.5% included in the 2020 PSU awards will be difficult to achieve. The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2020 PSUs, assuming a risk-free rate of 1.4% and volatility of 62.0%, the Company calculated the weighted average grant date fair value per PSU to be $5.36. As of December 31, 2020, there was $6.1 million of unrecognized compensation expense related to the PSU awards which will be amortized over a weighted average period of 0.88 years.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Credit Agreement On November 21, 2019, Earthstone, EEH (the “Borrower”), Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (“Wells Fargo”), Royal Bank of Canada, as Syndication Agent, BOKF, NA dba Bank of Texas (“BOKF”) as Issuing Bank with respect to Existing Letters of Credit, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, and the lenders party thereto (the “Lenders”) entered into a credit agreement (the “Credit Agreement”), which replaced the Prior Credit Agreement (as defined below), which was terminated on November 21, 2019. Concurrently with the effectiveness of the Credit Agreement, the Company terminated that certain credit agreement, dated as of May 9, 2017 (the “Prior Credit Agreement”), by and among the Borrower, Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden USA Operating, LLC, Bold Energy III LLC (“Bold”), Bold Operating, LLC, the guarantors party thereto, the lenders party thereto, and BOKF, as administrative agent. On March 27, 2020, in connection with a redetermination of the borrowing base under the Credit Agreement, the borrowing base was set at $275 million, representing a 15% decrease from the previous borrowing base of $325 million. On September 28, 2020, Earthstone, EEH, Wells Fargo, the guarantors party thereto, and the Lenders entered into an amendment (the “Amendment”) to the Credit Agreement. Among other things, the Amendment decreased the borrowing base from $275 million to $240 million, increased the interest rate on outstanding borrowings by 25 to 50 basis points, increased the flexibility to finance and make acquisitions, and added certain restrictions related to dividends and distributions. The next regularly scheduled redetermination of the borrowing base is on or around April 1, 2021. Subsequent redeterminations will occur on or about each November 1st and May 1st thereafter. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the adjusted LIBO Rate (as customarily defined) (the “Adjusted LIBO Rate”) plus 2.00% to 3.25% or (b) the sum of (i) the greatest of (A) the prime rate of Wells Fargo, (B) the federal funds rate plus ½ of 1.0%, and (C) the Adjusted LIBO Rate for an interest rate period of one month plus 1.0%, (ii) plus 1.00% to 2.25%, depending on the amount borrowed under the Credit Agreement. Principal amounts outstanding under the Credit Agreement are due and payable in full at maturity on November 21, 2024. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the Credit Agreement include paying a commitment fee of 0.375% to 0.50% per year, depending on the amount borrowed under the Credit Agreement, to the Lenders in respect of the unutilized commitments thereunder. EEH is also required to pay customary letter of credit fees. Effective May 2020, the Company entered into certain interest rate swaps, exchanging the LIBO Rate for a fixed rate of 0.286% (the “Swap”). The initial notional amount of the Swap is $125 million through May 2022 and decreases to $100 million through May 2023 and $75 million through May 2024. The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, pay dividends and distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the Credit Agreement requires EEH to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 and a consolidated leverage ratio of not greater than 3.5 to 1.0. Consolidated leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter to (ii) EBITDAX for the applicable period, which was calculated as EBITDAX for the four consecutive fiscal quarters ending on such date. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) certain distributions to employees related to the stock compensation, (vii) certain transaction related expenses, (viii) reimbursed indemnification expenses related to certain dispositions and investments, (ix) non-cash extraordinary, usual, or nonrecurring expenses or losses, (x) other non-cash charges and minus (b) to the extent included in consolidated net income in such period: (i) non-cash income, (ii) gains on asset dispositions, disposals and abandonments outside of the ordinary course of business and (iii) to the extent not otherwise deducted from consolidated net income, the aggregate amount of any pass-through cash distributions received by Borrower during such period in an amount equal to the aggregate amount of pass-through cash distributions actually made by Borrower during such period. The Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default and a change in control. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. At December 31, 2020, the Company was in compliance with all covenants under the Credit Agreement. As of December 31, 2020, the Company had a $240.0 million borrowing base under the Credit Agreement, of which $115.0 million was outstanding, bearing annual interest of 2.400%, resulting in an additional $125.0 million of borrowing base availability under the Credit Agreement. At December 31, 2019, there were $170.0 million of borrowings outstanding under the Credit Agreement. For the year ended December 31, 2020, the Company had borrowings of $136.1 million and $191.1 million in repayments of borrowings. For the years ended December 31, 2020 and 2019, interest on all outstanding debt averaged 2.83% and 4.42% per annum, respectively, which excluded commitment fees of $0.6 million and $0.7 million for each period ended, respectively, and amortization of deferred financing costs of $0.3 million and $0.4 million for each period ended, respectively. No costs associated with the Credit Agreement were capitalized during the year ended December 31, 2020. The Company capitalized $1.6 million of costs associated with the Credit Agreement for the year ended December 31, 2019. These capitalized costs are included in Other noncurrent assets in the Consolidated Balance Sheets. The Company’s policy is to capitalize the financing costs associated with its debt and amortize those costs on a straight-line basis over the term of the associated debt, which approximates the effective interest method over the term of the related debt. Amendment to the Credit Agreement On December 17, 2020, Earthstone, EEH, as Borrower, Wells Fargo Bank, National Association (“Wells Fargo”), as Administrative Agent, the guarantors party thereto, and the lenders party thereto (the “Lenders”) entered into an amendment (the “Amendment”) to the Credit Agreement. The Amendment was effective upon the closing of the acquisition described in Note 20. Subsequent Event

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate. The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended December 31, 2020 and 2019 (in thousands) : 2020 2019 Beginning asset retirement obligations $ 2,164 $ 2,229 Liabilities incurred 106 105 Property dispositions (10) (10) Liabilities settled (195) (374) Accretion expense 307 214 Revision of estimates 655 — Ending asset retirement obligations $ 3,027 $ 2,164

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions FASB ASC Topic 850, Related Party Disclosures , requires that information about transactions with related parties that would make a difference in decision making shall be disclosed so that users of the financial statements can evaluate their significance. Earthstone's significant shareholder consists of various investment funds managed by a private equity firm who may manage other investments in entities with which the Company interacts in the normal course of business. On February 12, 2020, the Company sold certain of its interests in oil and natural gas leases and wells in an arm’s length transaction to a portfolio company of Earthstone’s significant shareholder (not under common control) for cash consideration of approximately $0.4 million. In connection with the Olenik v. Lodzinski et al. lawsuit described below in Note 16. Commitments and Contingencies, Earthstone’s significant shareholder was also named in the lawsuit. As a result of the Settlement Agreement (defined below), the Company has concluded negotiations with its insurance carrier regarding an allocation of defense costs and settlement contributions above its deductible for all the parties named in the lawsuit.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Contractual Commitments Future minimum contractual commitments as of December 31, 2020 under non-cancelable agreements having initial or remaining terms in excess of one year are as follows: 2021 2022 2023 2024 2025 Thereafter Gas contract $ 680 $ — $ — $ — $ — $ — Office leases 791 696 595 605 152 — Automobile leases 75 5 — — — — Total $ 1,546 $ 701 $ 595 $ 605 $ 152 $ — The Company has a non-cancelable fixed cost agreement of $1.6 million per year through May 2021 to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing related to certain Eagle Ford assets in south Texas. As the operator of the properties dedicated to this contract, the gross amount of obligation is provided; however, the Company’s net share is approximately 31%. Additionally, the Company leases corporate office space in The Woodlands, Texas and Midland, Texas. Rent expense was approximately $0.8 million and $0.8 million, for the years ended December 31, 2020 and 2019, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2020 are shown in the table above. Environmental The Company’s operations are subject to risks normally associated with the drilling, completion and production of oil and gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Company to liabilities associated with these risks. In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks. However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above. Legal From time to time, Earthstone and its subsidiaries may be involved in various legal proceedings and claims in the ordinary course of business. Olenik v. Lodzinski et al.: On June 2, 2017, Nicholas Olenik filed a purported shareholder class and derivative action in the Delaware Court of Chancery against Earthstone’s Chief Executive Officer, along with other members of the Board, EnCap Investments L.P. (“EnCap”), Bold, Bold Holdings and Oak Valley Resources, LLC. The complaint alleges that Earthstone’s directors breached their fiduciary duties in connection with the contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 (the “Bold Contribution Agreement”), by and among Earthstone, EEH, Lynden US, Lynden USA Operating, LLC, Bold Holdings and Bold. The Plaintiff asserts that the directors negotiated the business combination pursuant to the Bold Contribution Agreement (the “Bold Transaction”) to benefit EnCap and its affiliates, failed to obtain adequate consideration for the Earthstone shareholders who were not affiliated with EnCap or Earthstone management, did not follow an adequate process in negotiating and approving the Bold Transaction and made materially misleading or incomplete proxy disclosures in connection with the Bold Transaction. The suit seeks unspecified damages and purports to assert claims derivatively on behalf of Earthstone and as a class action on behalf of all persons who held common stock up to March 13, 2017, excluding defendants and their affiliates. On July 20, 2018, the Delaware Court of Chancery granted the defendants’ motion to dismiss and entered an order dismissing the action in its entirety with prejudice. The Plaintiff filed an appeal with the Delaware Supreme Court. On April 5, 2019, the Delaware Supreme Court affirmed the Delaware Court of Chancery’s dismissal of the proxy disclosure claims but reversed the Delaware Court of Chancery’s dismissal of the other claims, holding that the allegations with respect to those claims were sufficient for pleading purposes. After engaging in extensive pre-trial discovery, the parties engaged in a mediation process that resulted in a non-binding settlement term sheet on September 21, 2020. On January 4, 2021, the parties executed and filed a Stipulation of Settlement (the “Settlement Agreement”) with the Delaware Court of Chancery. The principal terms of the Settlement Agreement are as follows: (i) a $3.5 million all-in cash settlement payment (the “Fund”) to be funded by defendants and/or their insurers into an escrow account, (ii) a bi-lateral complete and full release of all claims against defendants and plaintiffs, and (iii) that 55% of the Fund (the derivative payment) be paid to Earthstone to be used as determined by management, according to their fiduciary duties and business judgment, 45% of the Fund (the class payment) be paid to members of the class or current stockholders of Earthstone. The Company expects court approval of the Settlement Agreement and in addition estimates the insurance carriers and related affiliates to reimburse the Company in the amount of $2.8 million and $0.1 million, respectively. There is no assurance, however, that the court will approve the settlement. As described above, the Company expects to receive a portion of the derivative payment, however, the amount cannot be reasonably determined at this time. Through December 31, 2020, due to uncertainty of reimbursement, the Company recorded and accrued litigation costs when incurred and recorded insurance reimbursements as an offset only when proceeds were received in Transactions costs. In light of the Settlement Agreement, insurance carrier agreement on allocation of defense costs and settlement payment combined with the history of reimbursements from insurance carriers and related affiliate, a high probability of reimbursement exists. Accordingly, the Company has accrued $3.5 million related to the Settlement Agreement and estimated final defense costs associated with this legal action included in Accrued expenses in the Consolidated Balance Sheets, offset by an accrued $3.1 million of estimated reimbursements from insurance carriers and the majority shareholder which are included in Accounts receivable: Joint interest billings and other, net in the Consolidated Balance Sheets, with the impact of both items included in Transaction costs in the Consolidated Statements of Operations.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return which include Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the non-controlling interest. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax. The following table shows the components of the Company’s income tax provision for the years ended December 31, 2020 and 2019 ( in thousands ): Years Ended December 31, 2020 2019 Current: Federal $ — $ — State (545) — Total current (545) — Deferred: Federal 147 (95) State 510 (1,570) Total deferred 657 (1,665) Total income tax benefit (expense) $ 112 $ (1,665) Effective Tax Rate A reconciliation of the effective tax rate to the statutory rate for the years ended December 31, 2020 and 2019 is as follows ( in thousands, except percentages ): Years Ended December 31, 2020 2019 U.S. Canada Total U.S. Canada Total Net income (loss) before income taxes $ (29,546) $ — $ (29,546) $ 3,245 $ — $ 3,245 Statutory rate 21 % 27 % 21 % 21 % 27 % 21 % Tax expense computed at statutory rate (6,204) — (6,204) 681 — 681 Noncontrolling interest 3,349 — 3,349 (374) — (374) Non-deductible general and administrative expenses 1,943 — 1,943 230 — 230 State return to accrual 157 — 157 286 — 286 Refundable tax credits — — — — — — State income taxes, net of Federal benefit 35 — 35 1,285 — 1,285 Valuation allowance 608 — 608 (443) — (443) State rate change — — — — — — Total income tax (benefit) expense $ (112) $ — $ (112) $ 1,665 $ — $ 1,665 Effective tax rate 0.4 % — % 0.4 % 51.3 % — % 51.3 % During the year ended December 31, 2020, the Company recorded total income tax benefit of $0.11 million which included (1) deferred income tax benefit for Lynden US of $0.15 million as a result of its share of the distributable income from EEH, (2) deferred income tax benefit for Earthstone of $0.61 million as a result of its share of the distributable loss from EEH, which was offset by a valuation allowance as future realization of the net deferred tax asset cannot be assured and (3) current income tax expense of $0.55 million, offset by deferred income tax benefit of $0.51 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded total income tax expense of $1.7 million which included (1) deferred income tax expense for Lynden US of $0.1 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $0.4 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $1.6 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2019. 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, 2020 and 2019 are as follows ( in thousands ): Years Ended December 31, 2020 2019 Deferred noncurrent income tax assets (liabilities): Oil & gas properties $ 18,929 $ 20,633 Basis difference in subsidiary obligation (2,211) (2,211) Investment in Partnerships (25,760) (31,722) Federal net operating loss carryforward 11,590 14,597 Net deferred noncurrent tax assets 2,548 1,297 Valuation allowance (17,044) (16,451) Net deferred tax liability $ (14,496) $ (15,154) As of December 31, 2020, the Company had a valuation allowance recorded against its deferred tax assets of $17.0 million which is in excess of its net deferred noncurrent tax assets of $2.5 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal corporate income tax returns, one separate U.S. Federal partnership income tax return and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2020, the deferred tax assets and liabilities related to the two U.S. Federal corporate income tax returns, one Canadian income tax return and one related to the Texas Margin Tax are a $13.3 million deferred tax asset, a $9.6 million deferred tax liability, a $3.8 million deferred tax asset and a $4.8 million deferred tax liability, respectively, before considering the valuation allowance of $17.0 million. As of December 31, 2019, the Company had a valuation allowance recorded against its deferred tax assets of $16.5 million which is in excess of its Net deferred noncurrent tax assets of $1.3 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal income tax returns, one separate U.S. Federal partnership income tax return and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2019, the deferred tax assets and liabilities related to the two U.S. Federal income tax returns, one Canadian income tax and one related to the Texas Margin Tax were a $12.7 million deferred tax asset, a $9.7 million deferred tax liability, a $3.8 million deferred tax asset and a $5.5 million deferred tax liability, respectively, before considering the valuation allowance of $16.5 million. As of December 31, 2020, the Company had estimated U.S. net operating loss carryforwards of $42.4 million, the first expiring in 2034 and the last in 2040, and estimated Canadian net operating loss carryforwards of $10.0 million, the first expiring in 2024 and the last in 2037. The ability to utilize net operating losses and other tax attributes could be subject to a significant limitation if the Company were to undergo an ownership change for the purposes of Section 382 (“Sec 382”) of the Internal Revenue Code of 1986, as amended (the “Code”). The Company has an additional estimated U.S. net operating loss carryforward of $28.2 million limited by Sec 382 resulting from the Lynden Arrangement. The Company continues to evaluate the impact, if any, of potential Sec 382 limitations. The Company’s tax returns are subject to periodic audits by the various jurisdictions in which the Company operates. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable income. Generally, the Company’s income tax years 2014 through 2019 remain open and subject to examination by the Internal Revenue Service or state tax jurisdictions where it conducts operations. In certain jurisdictions, the Company operates through more than one legal entity, each of which may have different open years subject to examination. Uncertain Tax Positions FASB ASC Topic 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As of December 31, 2020, the Company had no material uncertain tax positions. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position. The Company files 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, 2020, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.

Defined Contribution Plan

Defined Contribution Plan	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Defined Contribution Plan	Defined Contribution PlanThe Company sponsors a 401(k) defined contribution plan (the “401(k) Plan”) for substantially all of its employees, which was initiated in April 2017. Eligible employees may make contributions to the 401(k) Plan by electing to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of 100% of employee contributions, not to exceed six percent of the employee’s annual eligible compensation. The Company’s matching contributions vest immediately. The Company’s contributions to the 401(k) Plan for the years ended December 31, 2020 and 2019 were $0.5 million and $0.5 million, respectively.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases	Leases The Company’s operating lease activities consist of leases for office space. The Company’s finance lease activities consist of leases for vehicles. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms generally ranging from one The following table shows the classification and location of the Company’s leases on the Consolidated Balance Sheets (in thousands) : December 31, Leases Balance Sheet Location 2020 2019 Assets Noncurrent: Operating Operating lease right-of-use assets $ 2,450 $ 3,108 Finance Office and other equipment, net of accumulated depreciation and amortization 74 614 Total lease assets $ 2,524 $ 3,722 Liabilities Current: Operating Operating lease liabilities $ 773 $ 570 Finance Finance lease liabilities 69 206 Noncurrent: Operating Operating lease liabilities 1,840 2,539 Finance Finance lease liabilities 5 85 Total lease liabilities $ 2,687 $ 3,400 The following table shows the classification and location of the Company’s lease costs on the Consolidated Statements of Operations (in thousands) : Years Ended December 31, Statement of Operations Location 2020 2019 Operating lease expense General and administrative expense $ 786 $ 754 Finance lease expense: Amortization of right-of-use assets Depreciation, depletion and amortization $ 217 $ 298 Interest on lease liability Interest expense, net 13 33 Total lease expense $ 1,016 $ 1,085 Additionally, the Company capitalized as part of oil and gas properties $2.9 million and $11.4 million of short-term lease costs related to drilling rig contracts during the years ended December 31, 2020 and 2019. All of the Company’s drilling rig contracts have enforceable terms of less than one year. Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2020 were as follows (in thousands) : Operating Finance 2021 $ 791 $ 72 2022 696 5 2023 595 — 2024 605 — 2025 152 — Thereafter — — Total lease payments $ 2,839 $ 77 Less imputed interest (226) (3) Total lease liability $ 2,613 $ 74 The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company’s leases: December 31, 2020 December 31, 2019 Operating Leases Finance Leases Operating Leases Finance Leases Weighted-average remaining lease term (in years) 3.9 1.0 4.8 1.4 Weighted-average discount rate (1) 4.35 % 6.71 % 4.35 % 6.75 % (1) The discount rate used for operating leases is based on the Company’s incremental borrowing rate at lease commencement and may be adjusted if modifications to lease terms or lease reassessments occur. The discount rate used for finance leases is based on the rates implicit in the leases. The following table includes other quantitative information for the Company’s leases (in thousands) : Years Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Cash payments for operating leases $ 632 $ 824 Cash payments for finance leases 130 392 Right-of-use assets obtained in exchange for new operating lease liabilities — 3,182
Leases	Leases The Company’s operating lease activities consist of leases for office space. The Company’s finance lease activities consist of leases for vehicles. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms generally ranging from one The following table shows the classification and location of the Company’s leases on the Consolidated Balance Sheets (in thousands) : December 31, Leases Balance Sheet Location 2020 2019 Assets Noncurrent: Operating Operating lease right-of-use assets $ 2,450 $ 3,108 Finance Office and other equipment, net of accumulated depreciation and amortization 74 614 Total lease assets $ 2,524 $ 3,722 Liabilities Current: Operating Operating lease liabilities $ 773 $ 570 Finance Finance lease liabilities 69 206 Noncurrent: Operating Operating lease liabilities 1,840 2,539 Finance Finance lease liabilities 5 85 Total lease liabilities $ 2,687 $ 3,400 The following table shows the classification and location of the Company’s lease costs on the Consolidated Statements of Operations (in thousands) : Years Ended December 31, Statement of Operations Location 2020 2019 Operating lease expense General and administrative expense $ 786 $ 754 Finance lease expense: Amortization of right-of-use assets Depreciation, depletion and amortization $ 217 $ 298 Interest on lease liability Interest expense, net 13 33 Total lease expense $ 1,016 $ 1,085 Additionally, the Company capitalized as part of oil and gas properties $2.9 million and $11.4 million of short-term lease costs related to drilling rig contracts during the years ended December 31, 2020 and 2019. All of the Company’s drilling rig contracts have enforceable terms of less than one year. Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2020 were as follows (in thousands) : Operating Finance 2021 $ 791 $ 72 2022 696 5 2023 595 — 2024 605 — 2025 152 — Thereafter — — Total lease payments $ 2,839 $ 77 Less imputed interest (226) (3) Total lease liability $ 2,613 $ 74 The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company’s leases: December 31, 2020 December 31, 2019 Operating Leases Finance Leases Operating Leases Finance Leases Weighted-average remaining lease term (in years) 3.9 1.0 4.8 1.4 Weighted-average discount rate (1) 4.35 % 6.71 % 4.35 % 6.75 % (1) The discount rate used for operating leases is based on the Company’s incremental borrowing rate at lease commencement and may be adjusted if modifications to lease terms or lease reassessments occur. The discount rate used for finance leases is based on the rates implicit in the leases. The following table includes other quantitative information for the Company’s leases (in thousands) : Years Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Cash payments for operating leases $ 632 $ 824 Cash payments for finance leases 130 392 Right-of-use assets obtained in exchange for new operating lease liabilities — 3,182

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event Midland Basin Acquisition On January 7, 2021, Earthstone, Earthstone Energy Holdings, LLC, a subsidiary of the Company (“EEH” and collectively with Earthstone, the “Buyer”), Independence Resources Holdings, LLC (“Independence”), and Independence Resources Manager, LLC (“Independence Manager” and collectively with Independence, the “Seller”) consummated the transactions contemplated in a Purchase and Sale Agreement dated December 17, 2020 (the “Purchase Agreement”). The Seller was unaffiliated with the Company. At the closing of the Purchase Agreement, among other things, EEH acquired (the “IRM Acquisition”) all of the issued and outstanding limited liability company interests in certain wholly owned subsidiaries of Independence and Independence Manager (collectively, the “Acquired Entities”) for aggregate consideration consisting of the following: (i) an aggregate amount of cash from EEH equal to approximately $131.2 million (the “Cash Consideration”) and (ii) 12,719,594 shares of the Company’s Class A Common Stock issued to Independence. Acquisition costs of $1.0 million related to the IRM Acquisition are included in Transaction costs in the Company's consolidated statements of operations for the year ended December 31, 2020. The acquisition will be accounted for as a business combination, with the fair value of consideration allocated to the acquisition date fair value of assets and liabilities acquired. The Company’s post-acquisition date results of operations of the Acquired Entities will be incorporated into the Company's interim condensed consolidated financial statements for the three months ended March 31, 2021.

Supplemental Information On Oil

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)	Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) Costs Incurred Related to Oil and Gas Activities Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. The Company’s oil and natural gas activities for 2020 and 2019 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows ( in thousands ): Years Ended December 31, 2020 2019 Acquisition cost (1) : Proved $ — $ (141) Unproved — (125) Exploration costs: Abandonment costs — 653 Geological and geophysical 298 — Development costs 67,550 210,520 Total additions $ 67,848 $ 210,907 (1) Acquisition costs incurred during 2019 consisted primarily of purchase price adjustments related to 2018 acquisitions . During the years ended December 31, 2020 and 2019, additions to oil and natural gas properties of $0.8 million and $0.1 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or acquired. During the years ended December 31, 2020 and 2019, the Company had no capitalized exploratory well costs, nor costs related to share-based compensation, general corporate overhead or similar activities. Capitalized Costs Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2020 and 2019, are summarized below ( in thousands ): December 31, 2020 2019 Oil and gas properties, successful efforts method: Proved properties $ 1,118,148 $ 1,046,208 Accumulated impairment to proved properties (100,652) (75,400) Proved properties, net of accumulated impairments 1,017,496 970,808 Unproved properties 301,083 305,961 Accumulated impairment to Unproved properties (67,316) (45,690) Unproved properties, net of accumulated impairments 233,767 260,271 Land 5,382 5,382 Total oil and gas properties, net of accumulated impairments 1,256,645 1,236,461 Accumulated depreciation, depletion and amortization (291,213) (195,567) Net oil and gas properties $ 965,432 $ 1,040,894 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, 2020 and 2019 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. The reserve information in these Consolidated Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. 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, 2020 and 2019 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices which equates to $39.57 per barrel and $55.69 per barrel, respectively. The natural gas prices as of December 31, 2020 and 2019 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $1.99 per MMBtu and $2.58 per MMBtu, respectively. Natural gas liquids are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics. The natural gas liquids prices used to value reserves as of December 31, 2020 and 2019 averaged $11.61 per barrel and $16.17 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials, resulting in the aforementioned oil, natural gas and natural gas liquids reserves as of December 31, 2020 being valued using prices of $38.90 per barrel, $0.97 per MMBtu and $11.61 per barrel, respectively. All prices are held constant in accordance with SEC guidelines. A summary of the Company’s changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2020 and 2019 are as follows: Oil Natural Gas NGLs Total Balance - December 31, 2018 59,034 113,217 20,943 98,847 Extensions and discoveries 3,598 4,476 721 5,065 Sales of minerals in place (31) (4) (1) (32) Production (3,086) (4,760) (1,022) (4,902) Revision to previous estimates (6,865) (4,939) 3,047 (4,642) Balance - December 31, 2019 52,650 107,990 23,688 94,336 Extensions and discoveries 420 1,258 230 860 Production (3,180) (7,282) (1,237) (5,630) Revision to previous estimates (9,800) 9,249 (2,432) (10,691) Balance - December 31, 2020 40,090 111,215 20,249 78,875 Proved developed reserves: December 31, 2018 14,325 26,110 4,969 23,646 December 31, 2019 18,220 35,120 7,447 31,521 December 31, 2020 18,878 55,764 10,125 38,298 Proved undeveloped reserves: December 31, 2018 44,709 87,107 15,974 75,201 December 31, 2019 34,430 72,870 16,241 62,815 December 31, 2020 21,212 55,450 10,123 40,577 The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2020 and 2019: As of December 31, 2020 Oil Natural Gas NGLs Total Proved developed 10,113 29,873 5,424 20,516 Proved undeveloped 11,363 29,704 5,423 21,737 Total proved 21,476 59,577 10,847 42,253 As of December 31, 2019 Oil Natural Gas NGLs Total Proved developed 9,933 19,146 4,060 17,183 Proved undeveloped 18,769 39,724 8,853 34,243 Total proved 28,702 58,870 12,913 51,426 Notable changes in proved reserves for the year ended December 31, 2020 included the following: • Extensions and discoveries. In 2020, total extensions and discoveries of 860.0 MBOE was the result of successful drilling results and well performance primarily related to the Midland Basin. • Revision to previous estimates. In 2020, the downward revisions of prior reserves of 10.7 MMBOE were primarily due to negative revisions due to price which included the reclassification of 11.9 MMBOE of reserves from proved undeveloped to non-proved due to the five-year development rule. Notable changes in proved reserves for the year ended December 31, 2019 included the following: • Extensions and discoveries. In 2019, total extensions and discoveries of 5.1 MMBOE was a result of successful drilling results and well performance primarily related to the Midland Basin. • Sales of minerals in place. Sales of minerals in place totaled 32.0 MBOE during 2019, resulting from the disposition of certain non-operated properties in the Midland Basin. See Note 3. Acquisitions and Divestitures . • Revision to previous estimates. In 2019, the downward revisions of prior reserves of 4.6 MMBOE were primarily due to reduced commodity prices. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and analogous producing wells for each area or field. PUD locations were limited to areas of uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the basis of available geoscience and engineering data. Changes in PUD reserves for the years ended December 31, 2020 and 2019 were as follows ( in MBOE ): Proved undeveloped reserves at December 31, 2018 (1) 75,201 Conversions to developed (10,254) Extensions and discoveries 1,230 Revision to previous estimates (3,362) Proved undeveloped reserves at December 31, 2019 (2) 62,815 Conversions to developed (8,200) Revision to previous estimates (14,038) Proved undeveloped reserves at December 31, 2020 (3) 40,577 (1) Includes 41,560 MBOE attributable to noncontrolling interests. (2) Includes 34,243 MBOE attributable to noncontrolling interests. (3) Includes 21,737 MBOE attributable to noncontrolling interests. 2020 Changes in Proved Undeveloped Reserves Conversions to developed . In our year-end 2019 plan to develop its PUDs within five years, we estimated that $111.1 million of capital would be expended in 2020 for the conversion of 28 gross / 17.6 net PUDs to add 11.3 MMBOE. In 2020, due to unforeseeable conditions previously described, we spent $67.8 million to convert 18 gross / 10.3 net PUDs adding 8.2 MMBOE to developed. Revision to previous estimates. We maintain a five-year development plan, reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations. In response to lower commodity prices, we reduced the pace of activity in our five-year development plan. This resulted in the reclassification of 11.9 MMBOE of reserves from proved undeveloped to non-proved during the year ended December 31, 2020 due to the five-year development rule. Based on our then-current acreage position, strip prices, anticipated well economics, and our development plans at the time these reserves were classified as proved, we believe the previous classification of these locations as proved undeveloped was appropriate. The remaining revisions of 2.1 MMBOE were primarily due to reduced commodity prices. 2019 Changes in Proved Undeveloped Reserves Conversions to developed . In the Company’s year-end 2018 plan to develop its PUDs within five years, the Company estimated that $103.8 million of capital would be expended in 2019 for the conversion of 30 gross / 12.30 net PUDs to add 9.9 MMBOE, which was consistent with the $111.5 million actually spent to convert 32 gross / 13.4 net PUDs adding 10.3 MMBOE to developed. Extensions and discoveries . Additionally, 1.2 MMBOE were added as extensions and discoveries due to successful drilling results on the Company’s acreage positions because of the wells it drilled. The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to the Company’s acreage. Revision to previous estimates. Revisions of 3.4 MMBOE were primarily due to reduced commodity prices. 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 FASB ASC Topic 932, Extractives Activities – Oil and Gas (“ASC 932”) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s third-party petroleum engineering firm. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company. The Company believes that the following factors should be taken into account when reviewing the following information: • Future costs and commodity prices will probably differ from those required to be used in these calculations; • Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; • A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and • Future net revenues may be subject to different rates of income taxation. At December 31, 2020 and 2019, 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 above. Future production costs include per-well overhead expenses allowed under joint operating agreements, abandonment costs (net of salvage value), and a non-cancelable fixed cost agreement to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. The Standardized Measure is as follows ( in thousands ): December 31, 2020 2019 Future cash inflows $ 1,902,073 $ 3,250,868 Future production costs (633,248) (1,027,464) Future development costs (285,088) (628,692) Future income tax expense (35,557) (58,824) Future net cash flows 948,180 1,535,888 10% annual discount for estimated timing of cash flows (487,327) (746,311) Standardized measure of discounted future net cash flows (1) $ 460,853 $ 789,577 (1) At December 31, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $246.9 million and $430.4 million, respectively. 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 two-year period ended December 31, 2020 ( in thousands ): December 31, 2020 2019 Beginning of year $ 789,577 $ 959,452 Sales of oil and gas produced, net of production costs (105,555) (150,708) Sales of minerals in place 14 (458) Net changes in prices and production costs (381,769) (565,240) Extensions, discoveries, and improved recoveries 14,644 127,182 Changes in income taxes, net 17,826 12,697 Previously estimated development costs incurred during the period 66,788 210,520 Net changes in future development costs 258,741 118,348 Revisions of previous quantity estimates (273,781) (35,588) Accretion of discount 81,999 107,432 Changes in timing of estimated cash flows and other (7,631) 5,940 End of year (1) $ 460,853 $ 789,577 (1) At December 31, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $246.9 million and $430.4 million, respectively.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The Consolidated Financial Statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation.
Use of Estimates	Use of Estimates The preparation of the Company’s Consolidated Financial Statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods then ended. Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of the Company’s estimates. All reserve data used in the preparation of the Consolidated Financial Statements, as well as included in Note 21. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) , 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, valuation of derivative instruments and valuation of certain performance-based restricted stock unit awards. 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 Note 21. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) . Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.
Accounts Receivable	Accounts Receivable Accounts receivable include estimated 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. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Derivative Instruments	Derivative Instruments The Company utilizes derivative instruments in order to manage exposure to risks associated with fluctuating commodity prices and interest rates. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are mark-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in Gain (loss) on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in Gain (loss) on derivative contracts, net in the Consolidated Statements of Operations.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties. For more information see Note 7. 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 indicate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors.
Office and Equipment	Office and Other EquipmentOffice and other equipment primarily includes leasehold improvements, vehicles, computer equipment and software, office furniture and fixtures and field equipment. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two years to 10 years.
Noncontrolling Interest	Noncontrolling InterestNoncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2020 and 2019, as well as an adjustment to Net income in the Consolidated Statement of Operations for the years ended December 31, 2020 and 2019.
Segment Reporting	Segment Reporting Operating segments are components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.
Asset Retirement Obligations	Asset Retirement ObligationsAsset 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.
Business Combinations	Business Combinations The Company accounts for its acquisitions of oil and gas properties not commonly controlled in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, which, among other things, requires the Company to determine if an asset or a business has been acquired. If the Company determines an asset(s) has been acquired, the asset(s) acquired, as well as any liabilities assumed, are measured and recorded at the acquisition date cost. If the Company determines a business has been acquired, the assets acquired and liabilities assumed are measured and recorded at their fair values as of the acquisition date, recording goodwill for amounts paid in excess of fair value.
Revenue Recognition	Revenue Recognition The Company’s revenues are comprised solely of revenues from customers and include the sale of oil, natural gas and natural gas liquids. The Company believes that the disaggregation of revenue into these three major product types, as presented in the Consolidated Statements of Operations, appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic region. Revenues are recognized when the recognition criteria of ASC 606 “Revenue from Contracts with Customers,” (“ASC 606”) are met, which generally occurs at a point in time when production is sold to a purchaser at a determinable price, delivery has occurred, control has transferred and collection of the revenue is probable . The Company fulfills its performance obligations under its customer contracts through delivery of oil, natural gas and natural gas liquids and revenues are recorded on a monthly basis and the Company receives payment from one to three months after delivery. Generally, each unit of product represents a separate performance obligation. The prices received for oil, natural gas and natural gas liquids sales under the Company’s contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, revenues from the sale of oil, natural gas and natural gas liquids will decrease if market prices decline. The sales of oil, natural gas and natural gas liquids, as presented on the Consolidated Statements of Operations, represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil, natural gas and natural gas liquids on behalf of royalty or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are recorded in “Accounts receivable: oil, natural gas, and natural gas liquids revenues” in the Consolidated Balance Sheets. As of December 31, 2020 and 2019 , amounts receivable from contracts with customers were $16.3 million and $29.0 million, respectively. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues in the Consolidated Statements of Operations. Oil Sales Oil production is transported from the wellhead to tank batteries or delivery points through flow-lines or gathering systems. Purchasers of the oil take delivery at (i) the tank batteries and transport the oil by truck, or (ii) at a pipeline delivery point and the Company collects a market price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the net price received by the Company. Starting in October 2019, certain of the Company’s oil sales activity involves buy/sell arrangements that effect a change in location with required repurchase of oil at a delivery point. Because the Company acts as the agent in these transactions, the buy/sell activity is recorded on a net basis and the residual transportation fee is included in Lease operating expenses in the Consolidated Statements of Operations. Natural Gas and NGL Sales Under the Company’s natural gas sales arrangements, the purchaser takes control of wet gas at a delivery point near the wellhead or at the inlet of the purchaser’s processing facility. The purchaser gathers and processes the wet gas and remits proceeds to the Company for the resulting natural gas and NGL sales. Based on the nature of these arrangements, the Company is the agent and the purchaser is the Company’s customer, thus, the Company recognizes natural gas and NGL sales based on the net amount of proceeds received from the purchaser. Imbalances The Company recognizes revenue for all oil, natural gas and NGL sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company had no imbalances as of December 31, 2020 or 2019. Contract Balances Under the Company’s product sales contracts, the Company invoices customers once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. Transaction Price Allocated to Remaining Performance Obligations Substantially all of the Company’s product sales are short-term in nature, with a contract term of one year or less. For these contracts, the Company has utilized the practical expedient in ASC 606 which exempts the Company from the requirements to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Prior-Period Performance Obligations The Company records revenue in the month that product is delivered to the purchaser. Settlement statements for certain natural gas and NGLs sales, however, may not be received for 30 to 90 days after the date the product is delivered, and as a result the Company is required to estimate the amount of product delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For the years ended December 31, 2020 and 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
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 the year ended December 31, 2020, three purchasers accounted for 32%, 15% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In the year ended December 31, 2019, three purchasers accounted for 30%, 14% and 12%, 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 the years ended December 31, 2020 and 2019. Additionally, at December 31, 2020, three purchasers accounted for 18%, 17% and 16%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. At December 31, 2019, three purchasers accounted for 46%, 14% and 10%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2020 or 2019. The Company holds working interests in oil and natural gas properties for which a third-party serves as operator. The operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In the year ended December 31, 2020, one operator distributed 15% of the Company’s oil, natural gas and natural gas liquids revenues. In the year ended December 31, 2019, no operator distributed 10% or more 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, 2020, the Company had a net derivative asset position of $6.6 million. At December 31, 2019, the Company had $2.7 million of derivative contracts that were in a material asset position. The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage.
Stock-Based Compensation	Stock-Based CompensationThe Company recognized stock-based compensation expense associated with restricted stock units, which include both time- and performance-based awards. The Company accounts for forfeitures of equity-based incentive awards as they occur. Stock-based compensation expense related to time-based restricted stock units is based on the price of the Class A common stock, $0.001 par value per share of Earthstone (“Class A Common Stock”), on the grant date and recognized over the vesting period using the straight-line method. Stock-based compensation expense related to performance-based restricted stock units, which cliff vest, is based on a grant date Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes fair value based on the most likely outcome, and is recognized over the vesting period using the straight-line method.
Income Taxes	Income Taxes The Company is a U.S. company operating in Texas, as of December 31, 2020, as well as one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which its operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the Consolidated Financial Statements, the Company is required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as its operations are conducted in different taxing jurisdictions. The Company records an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from Earthstone’s acquisition of Lynden Corp in May 2016 (the “Lynden Arrangement”) that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax. The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in the Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2020 and 2019, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets. The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. It requires that the Company recognize in the Consolidated Financial Statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management and they believe those positions would more likely than not be sustained upon
Recently Issued Accounting Standards	Recently Issued Accounting Standards Intangibles – Goodwill and Other – In January 2017, the FASB issued updated guidance simplifying the test for goodwill impairment. The update eliminates the requirement to determine the implied value of goodwill in measuring an impairment loss. Upon adoption, the measurement of a goodwill impairment will represent the excess of the reporting unit’s carrying value over its fair value and will be limited to the carrying value of goodwill. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The update is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements. See further discussion of goodwill in Note 8. Goodwill . Fair Value Measurements – In August 2018, the FASB issued an update which modifies the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements. Income Taxes - In December 2019, the FASB issued an update that simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020 and early adoption is permitted. The Company adopted the update effective January 1, 2021 and the impact was not material to the Consolidated Financial Statements. Credit Losses - In June 2016, the FASB issued an update that requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance is effective for interim and annual periods beginning after December 15, 2019. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements. Reference Rate Reform - In March 2020, the FASB issued an update that provides optional guidance for a limited period of time to ease the transition from LIBOR to an alternative reference rate. The ASU intends to address certain concerns relating to accounting for contract modifications and hedge accounting. These optional expedients and exceptions to applying GAAP, assuming certain criteria are met, are allowed through December 31, 2022. The Company is currently evaluating the provisions of this update and has not yet determined whether it will elect the optional expedients. The Company does not expect the transition to an alternative rate to have a material impact on its business, operations or liquidity.
Fair Value Measurements	FASB ASC Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets. The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows: Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the year ended December 31, 2020. 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 and interest rate swaps. The Company’s commodity price hedges and interest rate swaps are valued based on discounted future cash flow models that are primarily based on published forward commodity price curves and published LIBOR forward curves; thus, these inputs are designated as Level 2 within the valuation hierarchy. The fair values of derivative instruments in asset positions include measures of counterparty nonperformance risk, and the fair values of derivative instruments in liability positions include measures of the Company’s nonperformance risk. These measurements were not material to the Consolidated Financial Statements.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 Level 1 Level 2 Level 3 Total Financial assets Derivative asset- current $ — $ 7,509 $ — $ 7,509 Derivative asset- noncurrent — 396 — 396 Total financial assets $ — $ 7,905 $ — $ 7,905 Financial liabilities Derivative liability - current $ — $ 1,135 $ — $ 1,135 Derivative liability - noncurrent — 173 — 173 Total financial liabilities $ — $ 1,308 $ — $ 1,308 December 31, 2019 Financial assets Derivative asset- current $ — $ 8,860 $ — $ 8,860 Derivative asset- noncurrent — 770 — 770 Total financial assets $ — $ 9,630 $ — $ 9,630 Financial liabilities Derivative liability - current $ — $ 6,889 $ — $ 6,889 Derivative liability - noncurrent — — — — Total financial liabilities $ — $ 6,889 $ — $ 6,889

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Derivative Contracts	The following table sets forth the Company’s outstanding derivative contracts at December 31, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed. Period Commodity Volume Price 2021 Crude Oil Swap 2,294,000 $51.17 2021 Crude Oil Basis Swap (1) 1,825,000 $1.05 2022 Crude Oil Swap 365,000 $47.70 2021 Natural Gas Swap 4,380,000 $2.76 2021 Natural Gas Basis Swap (2) 4,380,000 $(0.45) (1) The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX. (2) The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
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, 2020 December 31, 2019 Derivatives not Balance Sheet Location Gross Gross Net Gross Gross Net Commodity contracts Derivative asset - current $ 11,071 $ (3,562) $ 7,509 $ 13,321 $ (4,461) $ 8,860 Commodity contracts Derivative liability - current $ 4,492 $ (3,562) $ 930 $ 11,350 $ (4,461) $ 6,889 Interest rate swaps Derivative liability - current $ 205 $ — $ 205 $ — $ — $ — Commodity contracts Derivative asset - noncurrent $ 396 $ — $ 396 $ 1,031 $ (261) $ 770 Commodity contracts Derivative liability - noncurrent $ — $ — $ — $ 261 $ (261) $ — Interest rate swaps Derivative liability - noncurrent $ 173 $ — $ 173 $ — $ — $ —
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 and Consolidated Statements of Cash Flows (in thousands) : Derivatives not designated as hedging contracts under ASC Topic 815 Years Ended December 31, Statement of Cash Flows Location Statement of Operations Location 2020 2019 Unrealized gain (loss) Not presented separately Not presented separately $ 3,855 $ (59,849) Realized gain Operating portion of net cash received in settlement of derivative contracts Not presented separately 56,044 15,866 Total (gain) loss on derivative contracts, net Gain (loss) on derivative contracts, net $ 59,899 $ (43,983)

Noncontrolling Interest (Tables

Noncontrolling Interest (Tables)	12 Months Ended
	Dec. 31, 2020
Noncontrolling Interest [Abstract]
Summary of Changes in Noncontrolling Interest	The following table presents the changes in noncontrolling interest for the year ended December 31, 2020: EEH Units Held By Earthstone and Lynden US % EEH Units Held By Others % Total EEH Units Outstanding As of December 31, 2019 29,421,131 45.5 % 35,260,680 54.5 % 64,681,811 EEH Units issued in connection with the vesting of restricted stock units 670,981 — 670,981 EEH Units and Class B Common Stock converted to Class A Common Stock 251,309 (251,309) — As of December 31, 2020 30,343,421 46.4 % 35,009,371 53.6 % 65,352,792

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Reconciliation of Net Loss Per Common Share	A reconciliation of Net (loss) income per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2020 2019 Net (loss) income attributable to Earthstone Energy, Inc. $ (13,547) $ 719 Net (loss) income per common share attributable to Earthstone Energy, Inc.: Basic $ (0.45) $ 0.02 Diluted $ (0.45) $ 0.02 Weighted average common shares outstanding Basic 29,911,625 28,983,354 Add potentially dilutive securities: Unvested restricted stock units — — Unvested performance units — 377,531 Diluted weighted average common shares outstanding 29,911,625 29,360,885

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Summary of Unvested RSU and PSU Award Activity	The table below summarizes unvested RSU activity for the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value Unvested RSUs at December 31, 2019 1,107,796 $ 6.60 Granted 859,100 $ 5.07 Forfeited (1,083) $ 5.19 Vested (914,905) $ 6.37 Unvested RSUs at December 31, 2020 1,050,908 $ 5.55 The table below summarizes performance unit (“PSU”) activity for the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value Unvested PSUs at December 31, 2019 835,625 $ 10.51 Granted 1,043,800 $ 5.36 Unvested PSUs at December 31, 2020 1,879,425 $ 7.65
Schedule Of Total Shareholder Return Goals	Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals: Earthstone’s Annualized TSR TSR Multiplier 23.9% or greater 2.0 14.5% 1.0 8.4% 0.5 Less than 8.4% 0.0

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 and 2019 (in thousands) : 2020 2019 Beginning asset retirement obligations $ 2,164 $ 2,229 Liabilities incurred 106 105 Property dispositions (10) (10) Liabilities settled (195) (374) Accretion expense 307 214 Revision of estimates 655 — Ending asset retirement obligations $ 3,027 $ 2,164

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Future Minimum Contractual Commitments under Non-cancelable Agreements	Future minimum contractual commitments as of December 31, 2020 under non-cancelable agreements having initial or remaining terms in excess of one year are as follows: 2021 2022 2023 2024 2025 Thereafter Gas contract $ 680 $ — $ — $ — $ — $ — Office leases 791 696 595 605 152 — Automobile leases 75 5 — — — — Total $ 1,546 $ 701 $ 595 $ 605 $ 152 $ —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 and 2019 ( in thousands ): Years Ended December 31, 2020 2019 Current: Federal $ — $ — State (545) — Total current (545) — Deferred: Federal 147 (95) State 510 (1,570) Total deferred 657 (1,665) Total income tax benefit (expense) $ 112 $ (1,665)
Reconciliation of Effective Tax Rate to Statutory Rate	A reconciliation of the effective tax rate to the statutory rate for the years ended December 31, 2020 and 2019 is as follows ( in thousands, except percentages ): Years Ended December 31, 2020 2019 U.S. Canada Total U.S. Canada Total Net income (loss) before income taxes $ (29,546) $ — $ (29,546) $ 3,245 $ — $ 3,245 Statutory rate 21 % 27 % 21 % 21 % 27 % 21 % Tax expense computed at statutory rate (6,204) — (6,204) 681 — 681 Noncontrolling interest 3,349 — 3,349 (374) — (374) Non-deductible general and administrative expenses 1,943 — 1,943 230 — 230 State return to accrual 157 — 157 286 — 286 Refundable tax credits — — — — — — State income taxes, net of Federal benefit 35 — 35 1,285 — 1,285 Valuation allowance 608 — 608 (443) — (443) State rate change — — — — — — Total income tax (benefit) expense $ (112) $ — $ (112) $ 1,665 $ — $ 1,665 Effective tax rate 0.4 % — % 0.4 % 51.3 % — % 51.3 %
Components of Deferred Tax Assets and Liabilities	Significant components of the deferred tax assets and liabilities at December 31, 2020 and 2019 are as follows ( in thousands ): Years Ended December 31, 2020 2019 Deferred noncurrent income tax assets (liabilities): Oil & gas properties $ 18,929 $ 20,633 Basis difference in subsidiary obligation (2,211) (2,211) Investment in Partnerships (25,760) (31,722) Federal net operating loss carryforward 11,590 14,597 Net deferred noncurrent tax assets 2,548 1,297 Valuation allowance (17,044) (16,451) Net deferred tax liability $ (14,496) $ (15,154)

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Assets And Liabilities Lessee	The following table shows the classification and location of the Company’s leases on the Consolidated Balance Sheets (in thousands) : December 31, Leases Balance Sheet Location 2020 2019 Assets Noncurrent: Operating Operating lease right-of-use assets $ 2,450 $ 3,108 Finance Office and other equipment, net of accumulated depreciation and amortization 74 614 Total lease assets $ 2,524 $ 3,722 Liabilities Current: Operating Operating lease liabilities $ 773 $ 570 Finance Finance lease liabilities 69 206 Noncurrent: Operating Operating lease liabilities 1,840 2,539 Finance Finance lease liabilities 5 85 Total lease liabilities $ 2,687 $ 3,400
Lease Cost Components	The following table shows the classification and location of the Company’s lease costs on the Consolidated Statements of Operations (in thousands) : Years Ended December 31, Statement of Operations Location 2020 2019 Operating lease expense General and administrative expense $ 786 $ 754 Finance lease expense: Amortization of right-of-use assets Depreciation, depletion and amortization $ 217 $ 298 Interest on lease liability Interest expense, net 13 33 Total lease expense $ 1,016 $ 1,085 The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company’s leases: December 31, 2020 December 31, 2019 Operating Leases Finance Leases Operating Leases Finance Leases Weighted-average remaining lease term (in years) 3.9 1.0 4.8 1.4 Weighted-average discount rate (1) 4.35 % 6.71 % 4.35 % 6.75 % (1) The discount rate used for operating leases is based on the Company’s incremental borrowing rate at lease commencement and may be adjusted if modifications to lease terms or lease reassessments occur. The discount rate used for finance leases is based on the rates implicit in the leases. The following table includes other quantitative information for the Company’s leases (in thousands) : Years Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Cash payments for operating leases $ 632 $ 824 Cash payments for finance leases 130 392 Right-of-use assets obtained in exchange for new operating lease liabilities — 3,182
Finance Lease, Liability, Maturity	Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2020 were as follows (in thousands) : Operating Finance 2021 $ 791 $ 72 2022 696 5 2023 595 — 2024 605 — 2025 152 — Thereafter — — Total lease payments $ 2,839 $ 77 Less imputed interest (226) (3) Total lease liability $ 2,613 $ 74
Lessee, Operating Lease, Liability, Maturity	Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2020 were as follows (in thousands) : Operating Finance 2021 $ 791 $ 72 2022 696 5 2023 595 — 2024 605 — 2025 152 — Thereafter — — Total lease payments $ 2,839 $ 77 Less imputed interest (226) (3) Total lease liability $ 2,613 $ 74

Supplemental Information On O_2

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Costs Incurred in Oil and Gas Producing Activities	The Company’s oil and natural gas activities for 2020 and 2019 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows ( in thousands ): Years Ended December 31, 2020 2019 Acquisition cost (1) : Proved $ — $ (141) Unproved — (125) Exploration costs: Abandonment costs — 653 Geological and geophysical 298 — Development costs 67,550 210,520 Total additions $ 67,848 $ 210,907 (1) Acquisition costs incurred during 2019 consisted primarily of purchase price adjustments related to 2018 acquisitions
Summary of Capitalized Costs, Impairment, and Depreciation, Depletion and Amortization	Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2020 and 2019, are summarized below ( in thousands ): December 31, 2020 2019 Oil and gas properties, successful efforts method: Proved properties $ 1,118,148 $ 1,046,208 Accumulated impairment to proved properties (100,652) (75,400) Proved properties, net of accumulated impairments 1,017,496 970,808 Unproved properties 301,083 305,961 Accumulated impairment to Unproved properties (67,316) (45,690) Unproved properties, net of accumulated impairments 233,767 260,271 Land 5,382 5,382 Total oil and gas properties, net of accumulated impairments 1,256,645 1,236,461 Accumulated depreciation, depletion and amortization (291,213) (195,567) Net oil and gas properties $ 965,432 $ 1,040,894
Summary of Changes in Quantities of Proved Oil and Natural Gas Reserves	A summary of the Company’s changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2020 and 2019 are as follows: Oil Natural Gas NGLs Total Balance - December 31, 2018 59,034 113,217 20,943 98,847 Extensions and discoveries 3,598 4,476 721 5,065 Sales of minerals in place (31) (4) (1) (32) Production (3,086) (4,760) (1,022) (4,902) Revision to previous estimates (6,865) (4,939) 3,047 (4,642) Balance - December 31, 2019 52,650 107,990 23,688 94,336 Extensions and discoveries 420 1,258 230 860 Production (3,180) (7,282) (1,237) (5,630) Revision to previous estimates (9,800) 9,249 (2,432) (10,691) Balance - December 31, 2020 40,090 111,215 20,249 78,875 Proved developed reserves: December 31, 2018 14,325 26,110 4,969 23,646 December 31, 2019 18,220 35,120 7,447 31,521 December 31, 2020 18,878 55,764 10,125 38,298 Proved undeveloped reserves: December 31, 2018 44,709 87,107 15,974 75,201 December 31, 2019 34,430 72,870 16,241 62,815 December 31, 2020 21,212 55,450 10,123 40,577 The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2020 and 2019: As of December 31, 2020 Oil Natural Gas NGLs Total Proved developed 10,113 29,873 5,424 20,516 Proved undeveloped 11,363 29,704 5,423 21,737 Total proved 21,476 59,577 10,847 42,253 As of December 31, 2019 Oil Natural Gas NGLs Total Proved developed 9,933 19,146 4,060 17,183 Proved undeveloped 18,769 39,724 8,853 34,243 Total proved 28,702 58,870 12,913 51,426
Changes in PUD Reserves	Changes in PUD reserves for the years ended December 31, 2020 and 2019 were as follows ( in MBOE ): Proved undeveloped reserves at December 31, 2018 (1) 75,201 Conversions to developed (10,254) Extensions and discoveries 1,230 Revision to previous estimates (3,362) Proved undeveloped reserves at December 31, 2019 (2) 62,815 Conversions to developed (8,200) Revision to previous estimates (14,038) Proved undeveloped reserves at December 31, 2020 (3) 40,577 (1) Includes 41,560 MBOE attributable to noncontrolling interests. (2) Includes 34,243 MBOE attributable to noncontrolling interests. (3) Includes 21,737 MBOE attributable to noncontrolling interests.
Schedule Of Standardized Measure	The Standardized Measure is as follows ( in thousands ): December 31, 2020 2019 Future cash inflows $ 1,902,073 $ 3,250,868 Future production costs (633,248) (1,027,464) Future development costs (285,088) (628,692) Future income tax expense (35,557) (58,824) Future net cash flows 948,180 1,535,888 10% annual discount for estimated timing of cash flows (487,327) (746,311) Standardized measure of discounted future net cash flows (1) $ 460,853 $ 789,577 (1) At December 31, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $246.9 million and $430.4 million, respectively.
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 two-year period ended December 31, 2020 ( in thousands ): December 31, 2020 2019 Beginning of year $ 789,577 $ 959,452 Sales of oil and gas produced, net of production costs (105,555) (150,708) Sales of minerals in place 14 (458) Net changes in prices and production costs (381,769) (565,240) Extensions, discoveries, and improved recoveries 14,644 127,182 Changes in income taxes, net 17,826 12,697 Previously estimated development costs incurred during the period 66,788 210,520 Net changes in future development costs 258,741 118,348 Revisions of previous quantity estimates (273,781) (35,588) Accretion of discount 81,999 107,432 Changes in timing of estimated cash flows and other (7,631) 5,940 End of year (1) $ 460,853 $ 789,577 (1) At December 31, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $246.9 million and $430.4 million, respectively.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2020USD ($)numberOfCustomersegment$ / shares	Dec. 31, 2019USD ($)numberOfCustomer$ / shares
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts receivable	$ 20,000	$ 100,000
Impairment of goodwill	17,620,000	0
Office and other equipment, net	931,000	1,311,000
Accumulated depreciation and amortization	3,675,000	3,180,000
Depreciation expense	$ 500,000	700,000
Number of reportable segment | segment	1
Receivables from contracts with customers	$ 16,300,000	29,000,000
Net derivative asset position	6,600,000	2,700,000
Oil, natural gas, and natural gas liquids revenues	$ 16,255,000	$ 29,047,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Expected lives of individual assets or group of assets	2 years
Maximum
Summary Of Significant Accounting Policies [Line Items]
Expected lives of individual assets or group of assets	10 years
Customer Concentration Risk | Sales Revenue, Net
Summary Of Significant Accounting Policies [Line Items]
Number of major customer | numberOfCustomer	3	3
Customer Concentration Risk | Sales Revenue, Net | Customer One
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk	32.00%	30.00%
Customer Concentration Risk | Sales Revenue, Net | Customer Two
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk	15.00%	14.00%
Customer Concentration Risk | Sales Revenue, Net | Customer Three
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk	12.00%	12.00%
Customer Concentration Risk | Accounts Receivable
Summary Of Significant Accounting Policies [Line Items]
Number of major customer | numberOfCustomer	3	3
Customer Concentration Risk | Accounts Receivable | Customer One
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk	18.00%	46.00%
Customer Concentration Risk | Accounts Receivable | Customer Two
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk	17.00%	14.00%
Customer Concentration Risk | Accounts Receivable | Customer Three
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk	16.00%	10.00%
Distributor Concentration Risk | Sales Revenue, Net
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk	15.00%
Class A Common Stock
Summary Of Significant Accounting Policies [Line Items]
Common stock, par value (in dollars per share) | $ / shares	$ 0.001	$ 0.001
Earthstone Energy Holdings Limited Liability Company And Lynden US | Earthstone Energy Holdings, LLC | Bold Contribution Agreement
Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership interest held by Earthstone Energy, Inc. and Lynden US Inc.	46.40%
Bold Energy Holdings, LLC | Earthstone Energy Holdings, LLC | Bold Contribution Agreement
Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership interest	53.60%

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Total cash consideration	$ 414	$ 4,184
Gain on sale of oil and gas properties, net	$ 204	3,222
Non-core Properties
Business Acquisition [Line Items]
Total cash consideration		4,200
Gain on sale of oil and gas properties, net		$ 3,600

Transaction Costs (Details)

Transaction Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Transaction costs	$ 622	$ 1,077
IRM Acquisition
Business Acquisition [Line Items]
Transaction costs	1,000
Other Potential Transactions
Business Acquisition [Line Items]
Transaction costs	300
Bold Transaction
Business Acquisition [Line Items]
Transaction costs		$ 1,100
Payments for reimbursement of expenses	$ 700

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Financial assets
Derivative asset- current	$ 7,509	$ 8,860
Derivative asset- noncurrent	396	770
Financial liabilities
Derivative liability - current	1,135	6,889
Derivative liability - noncurrent	173	0
Fair Value on a Recurring Basis
Financial assets
Derivative asset- current	7,509	8,860
Derivative asset- noncurrent	396	770
Total financial assets	7,905	9,630
Financial liabilities
Derivative liability - current	1,135	6,889
Derivative liability - noncurrent	173	0
Total financial liabilities	1,308	6,889
Level 1 | Fair Value on a Recurring Basis
Financial assets
Derivative asset- current	0	0
Derivative asset- noncurrent	0	0
Total financial assets	0	0
Financial liabilities
Derivative liability - current	0	0
Derivative liability - noncurrent	0	0
Total financial liabilities	0	0
Level 2 | Fair Value on a Recurring Basis
Financial assets
Derivative asset- current	7,509	8,860
Derivative asset- noncurrent	396	770
Total financial assets	7,905	9,630
Financial liabilities
Derivative liability - current	1,135	6,889
Derivative liability - noncurrent	173	0
Total financial liabilities	1,308	6,889
Level 3 | Fair Value on a Recurring Basis
Financial assets
Derivative asset- current	0	0
Derivative asset- noncurrent	0	0
Total financial assets	0	0
Financial liabilities
Derivative liability - current	0	0
Derivative liability - noncurrent	0	0
Total financial liabilities	$ 0	$ 0

Derivative Financial Instrume_3

Derivative Financial Instruments - Schedule of Outstanding Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2020MMBTU$ / MMBTU$ / bblbbl
Derivative Swap Contractual Period One | Natural Gas (MMcf)
Derivative [Line Items]
Natural gas volume (MMBtu) | MMBTU	4,380,000
Weighted average price ($/Bbl / $/MMBtu) | $ / MMBTU	2.76
Derivative Swap Contractual Period One | Crude Oil
Derivative [Line Items]
Crude oil volume (Bbl) | bbl	2,294,000
Weighted average price ($/Bbl / $/MMBtu) | $ / bbl	51.17
Crude Oil Derivative Basis Swap Contractual Period One | Crude Oil
Derivative [Line Items]
Crude oil volume (Bbl) | bbl	1,825,000
Weighted average price ($/Bbl / $/MMBtu) | $ / bbl	1.05
Crude Oil Derivative Basis Swap Contractual Period Two | Crude Oil
Derivative [Line Items]
Crude oil volume (Bbl) | bbl	365,000
Natural Gas Derivative Basis Swap Contractual Period One | Natural Gas (MMcf)
Derivative [Line Items]
Natural gas volume (MMBtu) | MMBTU	4,380,000
Short | Crude Oil Derivative Basis Swap Contractual Period Two | Crude Oil
Derivative [Line Items]
Weighted average price ($/Bbl / $/MMBtu) | $ / bbl	47.70
Short | Natural Gas Derivative Basis Swap Contractual Period One | Natural Gas (MMcf)
Derivative [Line Items]
Weighted average price ($/Bbl / $/MMBtu) | $ / MMBTU	0.45

Derivative Financial Instrume_4

Derivative Financial Instruments - Schedule of Location and Fair Value Amounts of All Derivative Instruments (Details) - Derivatives Not Designated as Hedging Contracts - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivative asset - current | Commodity Contracts
Derivatives, Fair Value [Line Items]
Gross recognized assets	$ 11,071	$ 13,321
Gross amounts offset, assets	(3,562)	(4,461)
Total financial assets	7,509	8,860
Derivative liability - current | Commodity Contracts
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	4,492	11,350
Gross amounts offset, liabilities	(3,562)	(4,461)
Total financial liabilities	930	6,889
Derivative liability - current | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	205	0
Gross amounts offset, liabilities	0	0
Total financial liabilities	205	0
Derivative asset - noncurrent | Commodity Contracts
Derivatives, Fair Value [Line Items]
Gross recognized assets	396	1,031
Gross amounts offset, assets	0	(261)
Total financial assets	396	770
Derivative liability - noncurrent | Commodity Contracts
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	0	261
Gross amounts offset, liabilities	0	(261)
Total financial liabilities	0	0
Derivative liability - noncurrent | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	173	0
Gross amounts offset, liabilities	0	0
Total financial liabilities	$ 173	$ 0

Derivative Financial Instrume_5

Derivative Financial Instruments - Summary of Realized and Unrealized Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain	$ (56,044)	$ (15,866)
(Loss) gain on commodity contracts, net	59,899	(43,983)
Derivatives Not Designated as Hedging Contracts | (Loss) Gain On Derivative Contracts, Net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	3,855	(59,849)
Realized gain	$ 56,044	$ 15,866

Oil and Natural Gas Properties

Oil and Natural Gas Properties - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Oil And Natural Gas Properties [Line Items]
Accumulated impairments to proved and unproved oil and natural gas properties	$ 168,000,000	$ 121,100,000
Eagle Ford Trend Properties
Oil And Natural Gas Properties [Line Items]
Accumulated impairments to proved and unproved oil and natural gas properties	13,200,000	0
Proved Oil and Natural Gas Properties
Oil And Natural Gas Properties [Line Items]
Depletion expenses	95,900,000	$ 68,500,000
Accumulated impairments to proved and unproved oil and natural gas properties	25,300,000
Unproved Oil and Gas Properties
Oil And Natural Gas Properties [Line Items]
Accumulated impairments to proved and unproved oil and natural gas properties	$ 8,400,000
Unproved Oil and Gas Properties | Minimum
Oil And Natural Gas Properties [Line Items]
Unproved oil and gas lease term	3 years
Unproved Oil and Gas Properties | Maximum
Oil And Natural Gas Properties [Line Items]
Unproved oil and gas lease term	5 years

Goodwill (Detail)

Goodwill (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Impairment of goodwill	$ 17,620,000	$ 0
Accumulated impairments to goodwill	$ 36,700,000	$ 19,100,000

Noncontrolling Interest - Summa

Noncontrolling Interest - Summary of Changes in Noncontrolling Interest (Details) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
December 31, 2018 (in shares)	29,421,131
December 31, 2019 (in shares)	30,343,421	29,421,131
Earthstone Energy Holdings, LLC
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
December 31, 2018 (in shares)	64,681,811
December 31, 2019 (in shares)	65,352,792	64,681,811
Earthstone Energy Holdings, LLC | Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH units issued in connection with the vesting of restricted stock units and issuance of class A common stock (in shares)	670,981
Class B common stock converted to class A common stock (in shares)	0
Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
December 31, 2018 (in shares)	29,421,131
December 31, 2019 (in shares)	30,343,421	29,421,131
Percentage of EEH units held by Earthstone and Lynden	46.40%	45.50%
Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US | Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH units issued in connection with the vesting of restricted stock units and issuance of class A common stock (in shares)	670,981
Class B common stock converted to class A common stock (in shares)	(251,309)
Earthstone Energy Holdings, LLC | EEH Units Held By Others
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
December 31, 2018 (in shares)	35,260,680
December 31, 2019 (in shares)	35,009,371	35,260,680
Percentage of EEH units held by others	53.60%	54.50%
Earthstone Energy Holdings, LLC | EEH Units Held By Others | Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH units issued in connection with the vesting of restricted stock units and issuance of class A common stock (in shares)	0
Class B common stock converted to class A common stock (in shares)	(251,309)

Net Income (Loss) Per Common _3

Net Income (Loss) Per Common Share - Reconciliation of Net Loss Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share [Abstract]
Net (loss) income attributable to Earthstone Energy, Inc.	$ (13,547)	$ 719
Net (loss) income per common share attributable to Earthstone Energy, Inc.:
Basic (in dollars per share)	$ (0.45)	$ 0.02
Diluted (in dollars per share)	$ (0.45)	$ 0.02
Weighted average common shares outstanding
Basic (in shares)	29,911,625	28,983,354
Add potentially dilutive securities:
Unvested restricted stock units (in shares)	0	0
Unvested performance units (in shares)	0	377,531
Diluted weighted average common shares outstanding (in shares)	29,911,625	29,360,885

Net Income (Loss) Per Common _4

Net Income (Loss) Per Common Share - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) attributable to noncontrolling interest	$ (15,887,000)	$ 861,000
Dilutive effect on net loss per common share attributable to Earthstone Energy, Inc	0
Earthstone Energy, Inc. Equity
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) attributable to noncontrolling interest	$ (15,900,000)	$ 900,000
Class B Common Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001

Common Stock (Details)

Common Stock (Details) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Member Units | Bold Contribution Agreement
Capital Unit [Line Items]
Conversion ratio (in shares)	1
Class A Common Stock
Capital Unit [Line Items]
Common stock, shares issued (in shares)	30,343,421	29,421,131
Common stock, shares outstanding (in shares)	30,343,421	29,421,131
Class A Common Stock | Bold Contribution Agreement
Capital Unit [Line Items]
Conversion ratio (in shares)	1
Class A Common Stock | 2014 Plan
Capital Unit [Line Items]
Common stock shares issued upon completion of public offering (in shares)	914,905	736,706
Treasury shares acquired (in shares)	243,924	203,394
Class B Common Stock
Capital Unit [Line Items]
Common stock, shares issued (in shares)	35,009,371	35,260,680
Common stock, shares outstanding (in shares)	35,009,371	35,260,680
Class B common stock converted to class A common stock (in shares)	251,309	191,498

Stock-Based Compensation - Narr

Stock-Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 28, 2019	Dec. 31, 2020	Dec. 31, 2019
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		859,100
Shares granted, weighted average grant date fair value (in dollars per share)		$ 5.07
Weighted average grant date fair value (in dollars per share)		$ 5.55	$ 6.60
Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		1,043,800
Shares granted, weighted average grant date fair value (in dollars per share)		$ 5.36
Risk free interest rate		1.40%
Expected volatility rate		62.00%
Weighted average grant date fair value (in dollars per share)		$ 7.65	$ 10.51
Compensation cost not yet recognized, period for recognition		10 months 17 days
2014 Long Term Incentive Plan | Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be issued under the plan (in shares)		9,400,000
Grant date fair value of units granted		$ 4.4	$ 6.5
Shares granted, weighted average grant date fair value (in dollars per share)		$ 5.07	$ 6.04
Vesting date fair value of units vested		$ 3	$ 4.2
Unrecognized compensation expense related to unvested stock		$ 5.7
Weighted average remaining vesting period of unrecognized compensation expense		11 months 23 days
Stock-based compensation expense		$ 5.4	5.9
2014 Long Term Incentive Plan | Restricted Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		12 months
2014 Long Term Incentive Plan | Restricted Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		36 months
2014 Long Term Incentive Plan | Restricted Stock Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		744,700
2014 Long Term Incentive Plan | Restricted Stock Units | Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		114,400
2014 Long Term Incentive Plan | Restricted Stock Units | Class A Common Stock | Bold Contribution Agreement
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock that each holder has contingent right to receive (in shares)		1
2014 Long Term Incentive Plan | Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		$ 4.6	$ 2.7
Weighted average grant date fair value (in dollars per share)		$ 5.36
Compensation not yet recognized, share-based awards other than options		$ 6.1
2014 Long Term Incentive Plan | Performance Share Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)	1,043,800

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Unvested RSU Award Activity (Details) - Restricted Stock Units	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Shares
Beginning period (in shares) | shares	1,107,796
Granted (shares) | shares	859,100
Forfeited (in shares) | shares	(1,083)
Vested (shares) | shares	(914,905)
End period (in shares) | shares	1,050,908
Weighted-Average Grant Date Fair Value
Beginning of period (in dollars per share) | $ / shares	$ 6.60
Granted (in dollars per share) | $ / shares	5.07
Forfeited (in dollars per share) | $ / shares	5.19
Vested (in dollars per share) | $ / shares	6.37
End of period (in dollars per share) | $ / shares	$ 5.55

Stock-Based Compensation - Su_2

Stock-Based Compensation - Summary of Unvested PSU Award Activity (Details) - Performance Share Units	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Shares
Beginning period (in shares) | shares	835,625
Shares granted (in shares) | shares	1,043,800
End period (in shares) | shares	1,879,425
Weighted-Average Grant Date Fair Value
Beginning of period (in dollars per share) | $ / shares	$ 10.51
Granted (in dollars per share) | $ / shares	5.36
End of period (in dollars per share) | $ / shares	$ 7.65

Stock-Based Compensation - TSR

Stock-Based Compensation - TSR Multiplier (Details) - Performance Share Units - Maximum	12 Months Ended
	Dec. 31, 2020
23.9% or greater
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	200000.00%
14.5%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	100000.00%
8.4%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	50000.00%
Less than 8.4%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	0.00%

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	Sep. 28, 2020	Mar. 27, 2020	Nov. 21, 2019	Dec. 31, 2020	Dec. 31, 2019	May 31, 2024	May 31, 2023	Dec. 18, 2020	Dec. 17, 2020	Sep. 27, 2020	May 31, 2020	Mar. 26, 2020
Debt Instrument [Line Items]
Long-term debt				$ 115,000,000	$ 170,000,000
Long-term debt, percentage bearing annual interest rate				2.40%
Amount of borrowings				$ 136,100,000
Repayments of borrowings				191,056,000	143,508,000
Commitment fees on borrowings				600,000	700,000
Amortization of deferred financing costs				322,000	412,000
Interest Rate Swap
Debt Instrument [Line Items]
Derivative fixed rate											0.286%
Notional amount											$ 125,000,000
Interest Rate Swap | Forecast
Debt Instrument [Line Items]
Notional amount						$ 75,000,000	$ 100,000,000
EEH Credit Agreement
Debt Instrument [Line Items]
Current borrowing base under EEH credit agreement	$ 240,000,000	$ 275,000,000		240,000,000				$ 360,000,000	$ 240,000,000	$ 275,000,000		$ 325,000,000
Decrease in borrowing base rate		15.00%
Covenant terms, minimum current ratio			1
Covenant terms, maximum leverage ratio			3.5
Long-term debt				115,000,000	$ 170,000,000
Additional borrowing base available under credit agreement				$ 125,000,000
EEH Credit Agreement | Minimum
Debt Instrument [Line Items]
Increase in interest rate on outstanding borrowings	0.25%
Applicable margin percentage			1.00%
Commitment fee percentage			0.375%
EEH Credit Agreement | Maximum
Debt Instrument [Line Items]
Interest rate, stated percentage	0.50%
Applicable margin percentage			2.25%
Commitment fee percentage			0.50%
EEH Credit Agreement | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Applicable margin percentage			1.00%
EEH Credit Agreement | London Interbank Offered Rate (LIBOR) | Minimum
Debt Instrument [Line Items]
Applicable margin percentage			2.00%
EEH Credit Agreement | London Interbank Offered Rate (LIBOR) | Maximum
Debt Instrument [Line Items]
Applicable margin percentage			3.25%
EEH Credit Agreement | Federal Funds Rate
Debt Instrument [Line Items]
Applicable margin percentage			0.50%
Earthstone Energy Credit Agreement
Debt Instrument [Line Items]
Averaged interest rate on outstanding debt				2.83%	4.42%
Capitalized costs associated with borrowings				$ 0	$ 1,600,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 2,164	$ 2,229
Liabilities incurred	106	105
Property dispositions	(10)	(10)
Liabilities settled	(195)	(374)
Accretion expense	307	214
Revision of estimates	655	0
Ending asset retirement obligations	3,027	2,164
Asset retirement obligation	$ 2,164	$ 2,164

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	Feb. 12, 2020USD ($)
Related Party Transactions [Abstract]
Proceeds form sale of oil and gas leases	$ 0.4

Commitments and Contingencies -

Commitments and Contingencies - Future Minimum Contractual Commitments under Non-cancelable Agreements (Details) $ in Thousands	Dec. 31, 2020USD ($)
Operating Leased Assets [Line Items]
2021	$ 791
2022	696
2023	595
2024	605
2025	152
Thereafter	0
Gas Contract
Operating Leased Assets [Line Items]
2021	680
2022	0
2023	0
2024	0
2025	0
Thereafter	0
Office Leases
Operating Leased Assets [Line Items]
2021	791
2022	696
2023	595
2024	605
2025	152
Thereafter	0
Automobile Leases
Operating Leased Assets [Line Items]
2021	75
2022	5
2023	0
2024	0
2025	0
Thereafter	0
Non-Cancelable Agreement
Operating Leased Assets [Line Items]
2021	1,546
2022	701
2023	595
2024	605
2025	152
Thereafter	$ 0

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) $ in Thousands, $ / MMBTU in Millions	Sep. 21, 2020USD ($)	Dec. 31, 2020USD ($)MMBTU$ / MMBTU	Dec. 31, 2019USD ($)MMBTU
Loss Contingencies [Line Items]
Lease operating expense		$ 29,131	$ 28,683
Remaining lease obligations		2,839
Settled Litigation
Loss Contingencies [Line Items]
Accrued settlement agreement costs		3,500
Estimated reimbursement from insurance carriers		3,100
Olenik v. Lodzinski | Settled Litigation
Loss Contingencies [Line Items]
All cash settlement payments	$ 3,500
Earthstone Energy, Inc. | Olenik v. Lodzinski | Settled Litigation
Loss Contingencies [Line Items]
Fund allocation, percent	55.00%
Current Stockholders | Olenik v. Lodzinski | Settled Litigation
Loss Contingencies [Line Items]
Fund allocation, percent	45.00%
Insurance Carrier | Olenik v. Lodzinski | Settled Litigation
Loss Contingencies [Line Items]
Cost expected to be reimbursed	$ 2,800
Related Affiliates | Olenik v. Lodzinski | Settled Litigation
Loss Contingencies [Line Items]
Cost expected to be reimbursed	$ 100
Texas
Loss Contingencies [Line Items]
Lease operating expense		$ 800	$ 800
Non-Cancelable Agreement
Loss Contingencies [Line Items]
Non-cancelable fixed cost agreement | $ / MMBTU		1.6
Holding pipeline capacity | MMBTU		10,000	10,000
Oil and gas delivery commitments and contracts, net share, percentage		31.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Current:
Federal	$ 0	$ 0
State	(545)	0
Total current	(545)	0
Deferred:
Federal	147	(95)
State	510	(1,570)
Total deferred	657	(1,665)
Total income tax (benefit) expense	$ 112	$ (1,665)

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Effective Tax Rate to Statutory Rate (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliation Of Income Tax Rate [Line Items]
Net income (loss) before income taxes	$ (29,546)	$ 3,245
Statutory rate	21.00%	21.00%
Tax expense computed at statutory rate	$ (6,204)	$ 681
Noncontrolling interest	3,349	(374)
Non-deductible general and administrative expenses	1,943	230
State return to accrual	157	286
Refundable tax credits	0	0
State income taxes, net of Federal benefit	35	1,285
Valuation allowance	608	(443)
State rate change	0	0
Total income tax (benefit) expense	$ (112)	$ 1,665
Effective tax rate	0.40%	51.30%
U.S.
Reconciliation Of Income Tax Rate [Line Items]
Net income (loss) before income taxes	$ (29,546)	$ 3,245
Statutory rate	21.00%	21.00%
Tax expense computed at statutory rate	$ (6,204)	$ 681
Noncontrolling interest	3,349	(374)
Non-deductible general and administrative expenses	1,943	230
State return to accrual	157	286
Refundable tax credits	0	0
State income taxes, net of Federal benefit	35	1,285
Valuation allowance	608	(443)
State rate change	0	0
Total income tax (benefit) expense	$ (112)	$ 1,665
Effective tax rate	0.40%	51.30%
Canada
Reconciliation Of Income Tax Rate [Line Items]
Net income (loss) before income taxes	$ 0	$ 0
Statutory rate	27.00%	27.00%
Tax expense computed at statutory rate	$ 0	$ 0
Noncontrolling interest	0	0
Non-deductible general and administrative expenses	0	0
State return to accrual	0	0
Refundable tax credits	0	0
State income taxes, net of Federal benefit	0	0
Valuation allowance	0	0
State rate change	0	0
Total income tax (benefit) expense	$ 0	$ 0
Effective tax rate	0.00%	0.00%

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Line Items]
Income tax expense (benefit)	$ (112)	$ 1,665
Current federal tax expense (benefit)	0	0
Current income tax expense	545	0
Deferred income tax expense (benefit)	(657)	1,665
Valuation allowance	17,044	16,451
Net deferred noncurrent tax assets	2,500	1,300
Deferred tax liabilities	14,496	15,154
U.S.
Income Tax Disclosure [Line Items]
Income tax expense (benefit)	(112)	1,665
Deferred tax assets	13,300	12,700
Deferred tax liabilities	9,600	9,700
Operating loss carryforward, net	42,400
Canada
Income Tax Disclosure [Line Items]
Income tax expense (benefit)	0	0
Deferred tax assets	3,800	3,800
Deferred tax liabilities	4,800	5,500
Operating loss carryforward, net	10,000
Lynden U S A Inc
Income Tax Disclosure [Line Items]
Current federal tax expense (benefit)	(150)	100
Lynden Arrangement | U.S.
Income Tax Disclosure [Line Items]
Operating loss carryforward, net	28,200
Earthstone Energy Holdings, LLC
Income Tax Disclosure [Line Items]
Current federal tax expense (benefit)	(610)	400
Deferred income tax expense (benefit)	$ (510)	$ 1,600

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred noncurrent income tax assets (liabilities):
Oil & gas properties	$ 18,929	$ 20,633
Basis difference in subsidiary obligation	(2,211)	(2,211)
Investment in Partnerships	(25,760)	(31,722)
Federal net operating loss carryforward	11,590	14,597
Net deferred noncurrent tax assets	2,548	1,297
Valuation allowance	(17,044)	(16,451)
Net deferred tax liability	$ (14,496)	$ (15,154)

Defined Contribution Plan (Deta

Defined Contribution Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, maximum annual contributions per employee, percent	100.00%
Defined contribution plan, employer contribution amount	$ 0.5	$ 0.5
Maximum
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, employer matching contribution, percent of match	6.00%

Leases - Narrative (Details)

Leases - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)option	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Number of renewal terms | option	1
Short-term lease cost | $	$ 2.9	$ 11.4
Minimum
Lessee, Lease, Description [Line Items]
Renewal term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Renewal term	3 years

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Assets and Liabilities, Lessee [Abstract]
Operating lease right-of-use assets	$ 2,450	$ 3,108
Office and other equipment, net of accumulated depreciation and amortization	74	614
Total lease assets	2,524	3,722
Operating Lease, Liability [Abstract]
Operating lease liability, current	773	570
Operating lease liability, noncurrent	1,840	2,539
Finance Lease Liability [Abstract]
Finance lease liability, current	69	206
Finance lease liability, noncurrent	5	85
Total lease liabilities	$ 2,687	$ 3,400

Leases - Consolidated Statement

Leases - Consolidated Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Lease operating expense	$ 29,131	$ 28,683
Total lease expense	1,016	1,085
General and administrative expense
Lessee, Lease, Description [Line Items]
Lease operating expense	786	754
Depreciation, depletion and amortization
Lessee, Lease, Description [Line Items]
Amortization of right-of-use assets	217	298
Interest expense, net
Lessee, Lease, Description [Line Items]
Interest on lease liability	$ 13	$ 33

Leases - Schedule of Future Min

Leases - Schedule of Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2020USD ($)
Operating
2021	$ 791
2022	696
2023	595
2024	605
2025	152
Thereafter	0
Total lease payments	2,839
Less imputed interest	(226)
Total lease liability	2,613
Finance
2021	72
2022	5
2023	0
2024	0
2025	0
Thereafter	0
Total lease payments	77
Less imputed interest	(3)
Total lease liability	$ 74

Leases - Quantitative Lease Inf

Leases - Quantitative Lease Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Cash payments for operating leases	$ 632	$ 824
Cash payments for finance leases	130	392
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 0	$ 3,182

Leases (Details)

Leases (Details)	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating lease, weighted average lease term	3 years 10 months 24 days	4 years 9 months 18 days
Operating lease, weighted average discount rate	4.35%	4.35%
Finance lease, weighted average lease term	1 year	1 year 4 months 24 days
Finance lease, weighted average discount rate	6.71%	6.75%

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details) - USD ($)	Jan. 07, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Transaction costs		$ 622,000	$ 1,077,000
IRM Acquisition
Business Acquisition [Line Items]
Transaction costs		$ 1,000,000
IRM Acquisition | Subsequent Event
Business Acquisition [Line Items]
Cash consideration	$ 131,200,000
IRM Acquisition | Subsequent Event | Class A Common Stock
Business Acquisition [Line Items]
Shares issued (in shares)	$ 12,719,594

Supplemental Information On O_3

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, 2020	Dec. 31, 2019
Acquisition cost:
Proved	$ 0	$ (141)
Unproved	0	(125)
Exploration costs:
Abandonment costs	0	653
Geological and geophysical	298	0
Development costs	67,550	210,520
Total additions	$ 67,848	$ 210,907

Supplemental Information On O_4

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Narrative (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)MMBTUMBoe$ / MMBTU$ / bbl	Dec. 31, 2019USD ($)MMBTUMBoe$ / bbl$ / MMBTU	Dec. 31, 2018USD ($)MBoe
Reserve Quantities [Line Items]
Additions to oil and gas properties | $	$ 67,848	$ 210,907
Natural gas liquids prices used to value reserves | $ / bbl	11.61	16.17
Oil prices used to value reserves (in dollars per barrel) | $ / bbl	38.90
Natural gas prices used to value reserves (in dollars per MMBtu) | $ / MMBTU	0.97
Natural gas liquids prices used to value reserves (in dollars per barrel) | $ / bbl	11.61
Proved extensions and discoveries	860,000	5,065,000
Downward revision to previous estimate	10,691,000	4,642,000
Sales of minerals in place		(32,000)
Conversion period of proved undeveloped reserves into proved developed producing reserves		5 years	5 years
Estimated capital expenditures of proved undeveloped reserves | $		$ 111,100	$ 103,800
Estimated proved undeveloped reserves, conversions to developed, gross		28,000	30
Estimated proved undeveloped reserves, conversions to developed, net		17,600	12,300
Estimated conversion of proved undeveloped reserves into proved developed producing reserves		11,300,000	9,900
Capital expenditures of proved undeveloped reserves | $	$ 67,800	$ 111,500
Modified proved undeveloped reserves, conversions to developed, gross	18,000	32,000
Modified proved undeveloped reserves, conversions to developed, net	10,300	13.4
Modified conversion of proved undeveloped reserves into proved developed producing reserves	(8,200,000)	10.3
Development plan	5 years
Reclassifications	11,900,000
Extensions and discoveries		1,230,000
Revisions	(14,038,000)	(3,362,000)
Remaining Revisions Of Proved Undeveloped Previous Estimate Energy		2,100,000
Non-Cancelable Agreement
Reserve Quantities [Line Items]
Holding pipeline capacity | MMBTU	10,000	10,000
Earthstone Energy Credit Agreement
Reserve Quantities [Line Items]
Capitalized costs associated with borrowings | $	$ 0	$ 1,600
Midland Basin
Reserve Quantities [Line Items]
Proved extensions and discoveries	860,000
Williston Basin
Reserve Quantities [Line Items]
Sales of minerals in place		(32,000)
Henry Hub Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas | $ / MMBTU	1.99	2.58
West Texas Intermediate Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil | $ / bbl	39.57	55.69
New Wells
Reserve Quantities [Line Items]
Additions to oil and gas properties | $	$ 800	$ 100
Operated Eagle Ford and Non-operated Bakken Properties
Reserve Quantities [Line Items]
Proved extensions and discoveries		5,100,000

Supplemental Information On O_5

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, 2020	Dec. 31, 2019
Oil and gas properties, successful efforts method:
Accumulated impairment	$ (168,000)	$ (121,100)
Proved properties, net of accumulated impairments	1,017,496	970,808
Unproved properties, net of accumulated impairments	233,767	260,271
Land	5,382	5,382
Total oil and gas properties, net of accumulated impairments	1,256,645	1,236,461
Accumulated depreciation, depletion and amortization	(291,213)	(195,567)
Net oil and gas properties	965,432	1,040,894
Proved property
Oil and gas properties, successful efforts method:
Proved properties	1,118,148	1,046,208
Accumulated impairment	(100,652)	(75,400)
Proved properties, net of accumulated impairments	1,017,496	970,808
Unproved property
Oil and gas properties, successful efforts method:
Accumulated impairment	(67,316)	(45,690)
Unproved properties	301,083	305,961
Unproved properties, net of accumulated impairments	$ 233,767	$ 260,271

Supplemental Information On O_6

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Changes in Quantities of Proved Oil and natural Gas Reserves (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2020MBoeMMcfMBbls	Dec. 31, 2019MBoeMBblsMMcf	Dec. 31, 2018MBoeMBblsMMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MBoe	94,336	98,847
Extensions and discoveries | MBoe	860	5,065
Sales of minerals in place | MBoe		32
Production | MBoe	(5,630)	(4,902)
Downward revision to previous estimate | MBoe	10,691	4,642
Ending Balance | MBoe	78,875	94,336
Proved developed reserves | MBoe	38,298	31,521	23,646
Proved undeveloped reserves | MBoe	40,577	62,815	75,201
Oil (MBbl)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	52,650	59,034
Extensions and discoveries	420	3,598
Sales of minerals in place		(31)
Production	(3,180)	(3,086)
Revision to previous estimates	(9,800)	(6,865)
Ending balance	40,090	52,650
Proved developed reserves	18,878	18,220	14,325
Proved undeveloped reserves	21,212	34,430	44,709
Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	107,990	113,217
Extensions and discoveries | MMcf	1,258	4,476
Sales of minerals in place | MMcf		(4)
Production | MMcf	(7,282)	(4,760)
Revision to previous estimates | MMcf	9,249	(4,939)
Ending Balance | MMcf	111,215	107,990
Proved developed reserves | MMcf	55,764	35,120	26,110
Proved undeveloped reserves | MMcf	55,450	72,870	87,107
NGLs (MBbl)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	23,688	20,943
Extensions and discoveries	230	721
Sales of minerals in place		(1)
Production	(1,237)	(1,022)
Revision to previous estimates	(2,432)	3,047
Ending balance	20,249	23,688
Proved developed reserves	10,125	7,447	4,969
Proved undeveloped reserves	10,123	16,241	15,974

Supplemental Information On O_7

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Changes in Quantities of Proved Oil and natural Gas and NGL Reserves Attributable to Noncontrolling Interests (Details)	Dec. 31, 2020MBoeMBblsMMcfMMBbls	Dec. 31, 2019MBoeMMBblsMBblsMMcf
Reserve Quantities [Line Items]
Proved developed | MBoe	20,516,000	17,183,000
Proved undeveloped | MBoe	21,737,000	34,243,000
Total proved | MBoe	42,253,000	51,426,000
Oil (MBbl)
Reserve Quantities [Line Items]
Proved undeveloped reserves, net attributable to noncontrolling interest, volume | MBbls	11,363,000	18,769,000
Proved developed and undeveloped reserves, net attributable to noncontrolling interest, volume | MBbls	21,476,000	28,702,000
Proved developed reserves, net attributable to noncontrolling interest, volume | MBbls	10,113,000	9,933,000
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Proved undeveloped reserves, net attributable to noncontrolling interest, gas | MMcf	29,704,000	39,724,000
Proved developed and undeveloped reserves, net attributable to noncontrolling interest, gas | MMcf	59,577,000	58,870,000
Proved developed reserves, net attributable to noncontrolling interest, gas | MMcf	29,873,000	19,146,000
NGLs (MBbl)
Reserve Quantities [Line Items]
Proved undeveloped reserves, net attributable to noncontrolling interest, volume | MMBbls	5,423,000	8,853,000
Proved developed and undeveloped reserves, net attributable to noncontrolling interest, volume | MMBbls	10,847,000	12,913,000
Proved developed reserves, net attributable to noncontrolling interest, volume | MMBbls	5,424,000	4,060,000

Supplemental Information On O_8

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule of Changes in Proved Undeveloped Reserves (Details) - MBoe	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Proved undeveloped reserves, Beginning Balance	62,815,000	75,201,000
Conversions to developed	(8,200,000)	(10,254,000)
Extensions and discoveries		1,230,000
Revision to previous estimates	(14,038,000)	(3,362,000)
Proved undeveloped reserves, Ending Balance	40,577,000	62,815,000
Proved undeveloped reserve attributable to noncontrolling interests	21,737,000	34,243,000	41,560,000

Supplemental Information On O_9

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule Of Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Future cash inflows	$ 1,902,073	$ 3,250,868
Future production costs	(633,248)	(1,027,464)
Future development costs	(285,088)	(628,692)
Future income tax expense	(35,557)	(58,824)
Future net cash flows	948,180	1,535,888
10% annual discount for estimated timing of cash flows	(487,327)	(746,311)
Standardized measure of discounted future net cash flows	460,853	789,577	$ 959,452
Standardized measure of discounted future net cash flows attributable to noncontrolling interests	$ 246,900	$ 430,400

Supplemental Information On _10

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - 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, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 789,577	$ 959,452
Sales of oil and gas produced, net of production costs	(105,555)	(150,708)
Sales of minerals in place	14	(458)
Net changes in prices and production costs	(381,769)	(565,240)
Extensions, discoveries, and improved recoveries	14,644	127,182
Changes in income taxes, net	17,826	12,697
Previously estimated development costs incurred during the period	66,788	210,520
Net changes in future development costs	258,741	118,348
Revisions of previous quantity estimates	(273,781)	(35,588)
Accretion of discount	81,999	107,432
Changes in timing of estimated cash flows and other	(7,631)	5,940
Standardized measure, end of year	460,853	789,577
Standardized measure of discounted future net cash flows attributable to noncontrolling interests	$ 246,900	$ 430,400