Earthstone Energy (ESTE) 10-K 9 Mar 22 2021 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Mar. 03, 2022	Jun. 30, 2021
Document And Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 263,687,345
Documents Incorporated by Reference	Portions of the Registrant’s Definitive Proxy Statement for its 2022 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	2021
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		73,301,255
Class B Common Stock
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		34,302,535

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Firm ID	659
Auditor Name	Moss Adams LLP
Auditor Location	Houston Texas

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash	$ 4,013	$ 1,494
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	50,575	16,255
Joint interest billings and other, net of allowance of $19 and $19 at December 31, 2021 and 2020, respectively	2,930	7,966
Derivative asset	1,348	7,509
Prepaid expenses and other current assets	2,549	1,509
Total current assets	61,415	34,733
Oil and gas properties, successful efforts method:
Proved properties	1,625,367	1,017,496
Unproved properties	222,025	233,767
Land	5,382	5,382
Total oil and gas properties	1,852,774	1,256,645
Accumulated depreciation, depletion and amortization	(395,625)	(291,213)
Net oil and gas properties	1,457,149	965,432
Other noncurrent assets:
Office and other equipment, net of accumulated depreciation of $4,547 and $3,675 at December 31, 2021 and 2020, respectively	1,986	931
Derivative asset	157	396
Operating lease right-of-use assets	1,795	2,450
Other noncurrent assets	33,865	1,315
TOTAL ASSETS	1,556,367	1,005,257
Current liabilities:
Accounts payable	31,397	6,232
Revenues and royalties payable	36,189	27,492
Accrued expenses	31,704	16,504
Asset retirement obligation	395	447
Derivative liability	45,310	1,135
Advances	4,088	2,277
Operating lease liability	681	773
Finance lease liability	0	69
Other current liabilities	851	565
Total current liabilities	150,615	55,494
Noncurrent liabilities:
Long-term debt	320,000	115,000
Asset retirement obligation	15,471	2,580
Derivative liability	571	173
Deferred tax liability	15,731	14,497
Operating lease liability	1,276	1,840
Finance lease liability	0	5
Other noncurrent liabilities	6,442	132
Total noncurrent liabilities	359,491	134,227
Commitments and Contingencies (Note 15)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding	0	0
Additional paid-in capital	718,181	540,074
Accumulated deficit	(159,774)	(195,258)
Total Earthstone Energy, Inc. equity	558,494	344,881
Noncontrolling interest	487,767	470,655
Total equity	1,046,261	815,536
TOTAL LIABILITIES AND EQUITY	1,556,367	1,005,257
Class A Common Stock
Equity:
Common stock	53	30
Class B Common Stock
Equity:
Common stock	$ 34	$ 35

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Joint interest billings and other, allowance	$ 19	$ 19
Office and other equipment, accumulated depreciation	$ 4,547	$ 3,675
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)	53,467,307	30,343,421
Common stock, shares outstanding (in shares)	53,467,307	30,343,421
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)	34,344,532	35,009,371
Common stock, shares outstanding (in shares)	34,344,532	35,009,371

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
REVENUES
Total revenues	$ 419,643	$ 144,523	$ 191,262
OPERATING COSTS AND EXPENSES
Lease operating expense	49,321	29,131	28,683
Production and ad valorem taxes	26,409	9,411	11,871
Rig idle and termination expense	0	426	0
Impairment expense	0	64,498	0
Depreciation, depletion and amortization	106,367	96,414	69,243
General and administrative expense	41,922	28,233	27,611
Transaction costs	4,875	622	1,077
Accretion of asset retirement obligation	1,065	307	214
Exploration expense	341	298	653
Total operating costs and expenses	230,300	229,340	139,352
Gain on sale of oil and gas properties, net	738	204	3,222
Income (loss) from operations	190,081	(84,613)	55,132
OTHER INCOME (EXPENSE)
Interest expense, net	(10,796)	(5,232)	(6,566)
Write-off of deferred financing costs	0	0	(1,242)
(Loss) gain on derivative contracts, net	(116,761)	59,899	(43,983)
Other income (expense), net	841	400	(96)
Total other (expense) income	(126,716)	55,067	(51,887)
Income (loss) before income taxes	63,365	(29,546)	3,245
Income tax (expense) benefit	(1,859)	112	(1,665)
Net income (loss)	61,506	(29,434)	1,580
Less:  Net income (loss) attributable to noncontrolling interest	26,022	(15,887)	861
Net income (loss) attributable to Earthstone Energy, Inc.	$ 35,484	$ (13,547)	$ 719
Net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic (in dollars per share)	$ 0.75	$ (0.45)	$ 0.02
Diluted (in dollars per share)	$ 0.71	$ (0.45)	$ 0.02
Weighted average common shares outstanding:
Basic (in shares)	47,169,948	29,911,625	28,983,354
Diluted (in shares)	49,952,093	29,911,625	29,360,885
Oil
REVENUES
Total revenues	$ 297,177	$ 120,355	$ 171,925
Natural gas
REVENUES
Total revenues	50,809	8,567	3,913
Natural gas liquids
REVENUES
Total revenues	$ 71,657	$ 15,601	$ 15,424

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Cumulative Effect, Period of Adoption, Adjustment	IRM Acquisition	Tracker Acquisition	Foreland Acquisition	Restricted Stock Units	Class A Common Stock	Class B Common Stock	Common StockClass A Common Stock	Common StockClass A Common StockIRM Acquisition	Common StockClass A Common StockTracker Acquisition	Common StockClass A Common StockForeland Acquisition	Common StockClass A Common StockRestricted Stock Units	Common StockClass B Common Stock	Additional Paid-in Capital	Additional Paid-in CapitalIRM Acquisition	Additional Paid-in CapitalTracker Acquisition	Additional Paid-in CapitalForeland Acquisition	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	Earthstone Energy, Inc. EquityIRM Acquisition	Earthstone Energy, Inc. EquityTracker Acquisition	Earthstone Energy, Inc. EquityForeland Acquisition	Noncontrolling Interest	Noncontrolling InterestCumulative Effect, Period of Adoption, Adjustment
Beginning balance (in 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]
Stock-based compensation expense	8,648														8,648							8,648
Shares issued in connection with IRM Acquisition (in shares)							0
Vesting of restricted stock units, net of taxes paid (in shares)													533,312
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings (in shares)									203,394
Vested restricted stock units 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 (loss)	1,580																			719		719					861
Ending balance (in 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]
Stock-based compensation expense	10,054														10,054							10,054
Shares issued in connection with IRM Acquisition (in shares)							0
Vesting of restricted stock units, net of taxes paid (in shares)													670,981
Vesting of restricted stock units, net of taxes paid													$ 1						$ (1)
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings (in shares)									243,924
Vested restricted stock units 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 (loss)	(29,434)																			(13,547)		(13,547)					(15,887)
Ending balance (in shares) at Dec. 31, 2020									30,343,421					35,009,371
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]
Stock-based compensation expense	9,132														9,132							9,132
Modification of performance units	(2,276)														(2,276)							(2,276)
Shares issued in connection with IRM Acquisition (in shares)										12,719,594	6,200,000	2,611,111
Shares issued in connection with IRM Acquisition			$ 76,572	$ 61,814	$ 28,121					$ 13	$ 6	$ 2				$ 76,559	$ 61,808	$ 28,119						$ 76,572	$ 61,814	$ 28,121
Vesting of restricted stock units, net of taxes paid (in shares)													928,342
Vesting of restricted stock units, net of taxes paid						$ 0							$ 1						$ (1)
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings (in shares)									453,483
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings	(4,144)														(4,144)							(4,144)
Cancellation of treasury shares (in shares)									(453,483)
Cancellation of treasury shares	0
Class B Common Stock converted to Class A Common Stock (in shares)								664,839	664,839					(664,839)
Class B Common Stock converted to Class A Common Stock	0								$ 1					$ (1)	8,910							8,910					(8,910)
Net income (loss)	61,506																			35,484		35,484					26,022
Ending balance (in shares) at Dec. 31, 2021									53,467,307					34,344,532
Ending balance at Dec. 31, 2021	$ 1,046,261								$ 53					$ 34	$ 718,181					$ (159,774)		$ 558,494					$ 487,767

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net income (loss)	$ 61,506,000	$ (29,434,000)	$ 1,580,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties	0	46,878,000	0
Depreciation, depletion and amortization	106,367,000	96,414,000	69,243,000
Accretion of asset retirement obligation	1,065,000	307,000	214,000
Impairment of goodwill	0	17,620,000	0
Gain on sale of oil and gas properties, net	(738,000)	(204,000)	(3,222,000)
Gain on sale of office and other equipment	(140,000)	0	0
Settlement of asset retirement obligations	(185,000)	(195,000)	(374,000)
Total loss (gain) on derivative contracts, net	116,761,000	(59,899,000)	43,983,000
Operating portion of net cash received in settlement of derivative contracts	(75,966,000)	56,044,000	15,866,000
Stock-based compensation	21,014,000	10,054,000	8,648,000
Deferred income taxes	1,859,000	(657,000)	1,665,000
Write-off of deferred financing costs	0	0	1,242,000
Amortization of deferred financing costs	856,000	322,000	412,000
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(19,061,000)	11,914,000	(18,035,000)
(Increase) decrease in prepaid expenses and other current assets	58,000	(203,000)	66,000
Increase (decrease) in accounts payable and accrued expenses	9,293,000	481,000	(10,438,000)
Increase (decrease) in revenues and royalties payable	5,985,000	(8,323,000)	7,067,000
Increase (decrease) in advances	2,200,000	(9,617,000)	8,331,000
Net cash provided by operating activities	230,874,000	131,502,000	126,248,000
Cash flows from investing activities:
Acquisition of oil and gas properties	(311,324,000)	0	0
Additions to oil and gas properties	(114,521,000)	(88,097,000)	(204,268,000)
Additions to office and other equipment	(1,365,000)	(114,000)	(527,000)
Proceeds from sale of oil and gas properties	975,000	414,000	4,184,000
Net cash used in investing activities	(426,235,000)	(87,797,000)	(200,611,000)
Cash flows from financing activities:
Proceeds from borrowings	744,132,000	136,056,000	234,680,000
Repayments of borrowings	(539,132,000)	(191,056,000)	(143,508,000)
Cash paid related to the exchange and cancellation of Class A Common Stock	(4,144,000)	(836,000)	(1,135,000)
Cash paid for finance leases	(70,000)	(130,000)	(392,000)
Deferred financing costs	(2,906,000)	(67,000)	(1,836,000)
Net cash (used in) provided by financing activities	197,880,000	(56,033,000)	87,809,000
Net increase (decrease) in cash	2,519,000	(12,328,000)	13,446,000
Cash at beginning of period	1,494,000	13,822,000	376,000
Cash at end of period	4,013,000	1,494,000	13,822,000
Cash paid for:
Interest	9,648,000	4,588,000	6,405,000
Income taxes	325,000	0	0
Non-cash investing and financing activities:
Accrued capital expenditures	23,558,000	7,328,000	28,356,000
Lease asset additions - ASC 842	0	0	3,722,000
Asset retirement obligations	2,178,000	762,000	105,000
IRM Acquisition
Non-cash investing and financing activities:
Class A Common Stock issued	76,572,000	0	0
Tracker/Sequel Acquisition
Non-cash investing and financing activities:
Class A Common Stock issued	61,814,000	0	0
Foreland Acquisition
Non-cash investing and financing activities:
Class A Common Stock issued	$ 28,121,000	$ 0	$ 0

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2021
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, 2021
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 $0.02 million at December 31, 2021 and 2020, 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 (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations. Oil and Natural Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties. 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. The Company had no goodwill recorded in the Consolidated Balance Sheets at December 31, 2021 or 2020. There were no impairments to Goodwill recorded in the year ended December 31, 2021. 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. 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 $2.0 million and $0.9 million, net of accumulated depreciation and amortization of $4.5 million and $3.7 million, at December 31, 2021 and 2020, respectively. During the years ended December 31, 2021, 2020 and 2019, the Company recognized depreciation expense of $0.7 million, $0.5 million and $0.7 million, respectively. See separate finance lease disclosures in Note 18. Leases . Noncontrolling Interest Noncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheets as of December 31, 2021 and 2020, as well as an adjustment to Net income in the Consolidated Statements of Operations for the years ended December 31, 2021 and 2020. As of December 31, 2021, Earthstone and Lynden US owned a 60.9% membership interest in EEH while Bold Energy Holdings, LLC (“Bold Holdings”), the noncontrolling third-party, owned the remaining 39.1%. See further discussion in Note 8. 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 13. 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, 2021 and 2020, amounts receivable from contracts with customers were $50.6 million and $16.3 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, 2021 or 2020. 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, 2021 and 2020, 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, 2021, two purchasers accounted for 34% and 13%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. 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, 2021, 2020 or 2019. Additionally, at December 31, 2021, three purchasers accounted for 26%, 21% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. 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. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2021 and 2020. 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, 2021, one operator distributed 13% of the Company’s oil, natural gas and natural gas liquids revenues. 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, 2021, the Company had a net derivative liability position of $44.4 million. At December 31, 2020, the Company had $6.6 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. The Company classifies grants to be settled in shares as equity awards and awards to be settled in cash a liability awards. The Company accounts for these awards 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. The fair value of the liability awards is updated on a quarterly basis. See Note 11. Stock-Based Compensation for further details. Income Taxes The Company is a U.S. company operating in Texas, as of December 31, 2021, and includes 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, 2021 and 2020, 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, 2021 or 2020. Recently Issued Accounting Standards 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. 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, 2021
Business Combination and Asset Acquisition [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. IRM Acquisition As part of the execution of its growth strategy to further increase its scale, on January 7, 2021, the Company completed the acquisition (the “IRM Acquisition”) of all of the issued and outstanding limited liability company interests in Independence Resources Management, LLC (“IRM”) and certain wholly owned subsidiaries for consideration consisting of (i) net cash of approximately $140.5 million and (ii) 12,719,594 shares of Class A Common Stock. The fair value of each share of Class A Common Stock was determined using the closing price of $6.02 per share on January 7, 2021. The purchase agreement contained customary representations and warranties for transactions of this nature. The Company obtained representation and warranty insurance to provide coverage in the event of certain breaches of representations and warranties of the seller contained in the purchase agreement, which are subject to various exclusions, deductibles and other terms and conditions set forth therein. The IRM Acquisition was accounted for as a business combination using the acquisition method of accounting, with Earthstone identified as the acquirer. The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price): Consideration: Shares of Class A Common Stock issued 12,719,594 Class A Common Stock price as of January 7, 2021 $ 6.02 Class A Common Stock consideration 76,572 Cash consideration 140,507 Total consideration transferred $ 217,079 Fair value of assets acquired: Cash $ 4,763 Other current assets 11,524 Oil and gas properties 224,112 Other non-current assets 252 Amount attributable to assets acquired $ 240,651 Fair value of liabilities assumed: Derivative liability $ 10,177 Other current liabilities 5,196 Asset retirement obligation - noncurrent 8,199 Amount attributable to liabilities assumed $ 23,572 Tracker/Sequel Acquisitions On March 31, 2021, Earthstone, EEH, Tracker Resource Development III, LLC, a Delaware limited liability company (“Tracker Opco”), and TRD III Royalty Holdings (TX), LP, a Delaware limited partnership (“RoyaltyCo” and collectively with Tracker Opco, “Tracker”), entered into a purchase and sale agreement (the “Tracker Agreement”), which provided that EEH would acquire (the “Tracker Acquisition”) interests in oil and gas leases and related property of Tracker located in Irion County, Texas (the “Tracker Assets”). Also on March 31, 2021, Earthstone, EEH, SEG-TRD LLC, a Delaware limited liability company (“SEG-I”), and SEG-TRD II LLC, a Delaware limited liability company (“SEG-II” and collectively with SEG-I, “Sequel”) entered into a purchase and sale agreement (the “Sequel Agreement” and collectively with the Tracker Agreement, the “Tracker/Sequel Purchase Agreements”), which provided that EEH would acquire (the “Sequel Acquisition” and collectively with the Tracker Acquisition, the “Tracker/Sequel Acquisitions”) certain well-bore interests and related equipment (the “Sequel Assets”). On July 20, 2021, Earthstone, EEH and Tracker consummated the transactions contemplated in the Tracker Agreement. At the closing of the Tracker Agreement, among other things, EEH acquired the Tracker Assets for aggregate consideration consisting of: (i) $18.8 million in cash, net of customary purchase price adjustments, and (ii) 4.7 million shares of Class A Common Stock. Also, on July 20, 2021, Earthstone, EEH and Sequel consummated the transactions contemplated in the Sequel Agreement. At the closing of the Sequel Agreement, among other things, EEH acquired the Sequel Assets for aggregate consideration consisting of: (i) $41.4 million in cash, net of customary purchase price adjustments, and (ii) 1.5 million shares of Class A Common Stock. The Significant Shareholder, as described in the Note referenced below, owned approximately 49% of Tracker as of the closing of the Tracker Acquisition. See Note 14. Related Party Transactions for further discussion. In accordance with ASC Topic 805, Business Combinations (referred to as “ASC 805”), the Tracker/Sequel Acquisitions have been accounted for as asset acquisitions. The preliminary allocation of the total purchase price in the Tracker/Sequel Acquisitions is based upon management’s estimates of and assumptions related to the relative fair value of assets acquired and liabilities assumed. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the acquired oil and natural gas properties. These amounts will be finalized no later than one year from the acquisition date. The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price): Total Consideration: Shares of Earthstone Class A Common Stock issued 6,200,000 Earthstone Class A Common Stock price as of July 20, 2021 $ 9.97 Class A Common Stock consideration 61,814 Cash consideration (1) 60,159 Direct transaction costs (2) 1,579 Total consideration transferred $ 123,552 Fair value of assets acquired: Oil and gas properties $ 124,152 Amount attributable to assets acquired $ 124,152 Fair value of liabilities assumed: Noncurrent liabilities - ARO 600 Amount attributable to liabilities assumed $ 600 (1) Includes customary purchase price adjustments. (2) Represents $1.6 million of transaction costs associated with the Tracker Acquisition and the Sequel Acquisition that have been capitalized in accordance with ASC 805-50. The following unaudited supplemental pro forma condensed results of operations present consolidated information as though the IRM Acquisition and Tracker/Sequel Acquisitions had been completed as of January 1, 2020. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for IRM, Tracker, Sequel and Earthstone and adjusted to include depletion expense applied to the adjusted basis of the properties acquired. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the Company for the periods presented or that may be achieved by the Company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts): Years Ended December 31, 2021 2020 Revenue $ 460,948 $ 287,359 Income (loss) before taxes 88,917 (239,752) Net income (loss) 87,058 (239,980) Less: Net income (loss) attributable to noncontrolling interest 36,833 (99,695) Net income (loss) attributable to Earthstone Energy, Inc. 50,226 (140,285) Pro forma net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic $ 1.06 $ (2.87) Diluted $ 1.01 $ (2.87) The Company has included in its Consolidated Statements of Operations, revenues of $95.1 million and operating expenses of $44.4 million for the period from January 7, 2021 to December 31, 2021 related to the IRM Acquisition. During the year ended December 31, 2021, the Company recorded $4.0 million of legal and professional fees, and employee severance costs related to the IRM Acquisition which are included in Transaction costs in the Consolidated Statements of Operations. Additionally, the Company has included in its Consolidated Statements of Operations, revenues of $40.5 million and operating expenses of $11.5 million for the period July 20, 2021 to December 31, 2021 related to the Tracker/Sequel Acquisitions. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change. Eagle Ford Acquisitions In May and June 2021, the Company completed acquisitions of working interests in certain assets it operates located in southern Gonzales County, Texas (collectively, the “Eagle Ford Acquisitions”) from four separate sellers. The aggregate purchase price of the Eagle Ford Acquisitions was approximately $45.2 million. One of the four separate sellers was a related party. See Note 14. Related Party Transactions for further discussion. The Eagle Ford Acquisitions have been accounted for as asset acquisitions in accordance with ASC 805. The preliminary allocation of each purchase was based upon management’s estimates of and assumptions related to the relative fair value of assets acquired and liabilities assumed. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the acquired oil and natural gas properties. These amounts will be finalized no later than one year from the acquisition date. Foreland-BCC Acquisition On November 2, 2021, Earthstone, EEH and Foreland Investments LP, a Delaware limited partnership (“Foreland”), consummated the transactions contemplated in the Purchase and Sale Agreement dated as of September 30, 2021 by and among Earthstone, EEH and Foreland (the “Foreland Purchase Agreement”). At the closing of the Foreland Purchase Agreement, EEH acquired (the “Foreland Acquisition”) interests in oil and gas leases and related property of Foreland located in Irion County and Crockett County, Texas, for a purchase price consisting of: (i) $16.3 million in cash, net of customary purchase price adjustments, and (ii) 2,611,111 shares of Class A Common Stock. Also, on November 2, 2021, Earthstone, EEH and BCC-Foreland LLC, a Delaware limited liability company (“BCC”), consummated the transactions contemplated in the Purchase and Sale Agreement dated as of September 30, 2021 by and among Earthstone, EEH and BCC (the “BCC Purchase Agreement”). At the closing of the BCC Purchase Agreement, EEH acquired (the “BCC Acquisition” and with the Foreland Acquisition, the “Foreland-BCC Acquisition”) certain well-bore interests and related equipment held by BCC that were part of a joint development agreement between Foreland, Foreland Operating, LLC, and BCC involving portions of the acreage covered by the Foreland Purchase Agreement for a purchase price of $23.0 million in cash, net of customary purchase price adjustments. Divestitures

Transaction Costs

Transaction Costs	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Transaction Costs	Transaction Costs During the year ended December 31, 2021, the Company recorded transaction costs primarily due to legal, consulting and other fees of approximately $4.0 million related to the IRM Acquisition, $1.8 million related to the Chisholm Acquisition and $0.3 million related to other potential transactions, offset by net reimbursements of $1.2 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, 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 Bold Transaction. 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, 2021
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, 2021. Fair Value on a Recurring Basis Derivative Financial Instruments Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of fixed price swaps, basis swaps and costless collars 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. Share-based Compensation Liability Certain of our performance-based stock awards (“PSUs”) may be payable in cash. The Company classifies the awards that may be settled in cash as liability awards. These awards are valued quarterly 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. The inputs for the Monte Carlo model are designated as Level 2 within the valuation hierarchy. The share-based compensation liability related to the PSU liability awards is included in Accrued expenses and Other noncurrent liabilities in the Consolidated Balance Sheet as of December 31, 2021. 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, 2021 Level 1 Level 2 Level 3 Total Financial assets Derivative asset- current $ — $ 1,348 $ — $ 1,348 Derivative asset- noncurrent — 157 — 157 Total financial assets $ — $ 1,505 $ — $ 1,505 Financial liabilities Derivative liability - current $ — $ 45,310 $ — $ 45,310 Derivative liability - noncurrent — 571 — 571 Share-based compensation liability - noncurrent — 14,159 — 14,159 Total financial liabilities $ — $ 60,040 $ — $ 60,040 December 31, 2020 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 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

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2021
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, basis swaps and costless collars. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum (sold ceiling) and a minimum (bought floor) future price. 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, 2021. When aggregating multiple contracts, the weighted average contract price is disclosed. Period Commodity Volume Price 2022 Crude Oil Swap 2,768,250 $57.69 2022 Crude Oil Basis Swap (1) 3,832,500 $0.51 2022 Natural Gas Swap 5,900,000 $3.20 2022 Natural Gas Basis Swap (2) 9,100,000 $(0.26) 2023 Natural Gas Swap 1,375,000 $3.27 (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. Costless Collars Period Commodity Volume Bought Floor Sold Ceiling 2022 Crude Oil Costless Collar 730,000 $60.00 $73.73 2023 Crude Oil Costless Collar 365,000 $55.00 $71.75 2022 Natural Gas Costless Collar 4,037,500 $3.43 $5.10 2023 Natural Gas Costless Collar 888,000 $3.25 $5.13 Interest Rate Swaps At times, the Company’s hedging activities include the use of interest rate swaps entered into in order to manage cash flow variability resulting from changes in interest rates. These derivative instruments are not accounted for under hedge accounting. In December 2021, the Company unwound its interest rate swap contracts, receiving a one-time settlement payment of $1.1 million. The Company had no interest rate swaps in place as of December 31, 2021. 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, 2021 December 31, 2020 Derivatives not Balance Sheet Location Gross Gross Net Gross Gross Net Commodity contracts Derivative asset - current $ 3,191 $ (1,843) $ 1,348 $ 11,071 $ (3,562) $ 7,509 Commodity contracts Derivative liability - current $ 47,153 $ (1,843) $ 45,310 $ 4,492 $ (3,562) $ 930 Interest rate swaps Derivative liability - current $ — $ — $ — $ 205 $ — $ 205 Commodity contracts Derivative asset - noncurrent $ 2,721 $ (2,564) $ 157 $ 396 $ — $ 396 Commodity contracts Derivative liability - noncurrent $ 3,135 $ (2,564) $ 571 $ — $ — $ — 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 2021 2020 2019 Unrealized (loss) gain Not presented separately Not presented separately $ (40,795) $ 3,855 $ (59,849) Realized (loss) gain Operating portion of net cash received in settlement of derivative contracts Not presented separately (75,966) 56,044 15,866 Total loss (gain) on derivative contracts, net (Loss) gain on derivative contracts, net $ (116,761) $ 59,899 $ (43,983)

Oil and Natural Gas Properties

Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2021
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 $105.7 million, $95.9 million and $68.5 million for the years ended December 31, 2021, 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 The Company recorded no non-cash asset impairment charges for the year ended December 31, 2021. 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, 2021 and 2020 were $168.0 million and $168.0 million, respectively.

Noncontrolling Interest

Noncontrolling Interest	12 Months Ended
	Dec. 31, 2021
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, 2021 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, 2021 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, 2021: EEH Units Held By Earthstone and Lynden US % EEH Units Held By Others % Total EEH Units Outstanding As of December 31, 2020 30,343,421 46.4 % 35,009,371 53.6 % 65,352,792 EEH Units issued in connection with the IRM Acquisition 12,719,594 — 12,719,594 EEH Units issued in connection with the Tracker/Sequel Acquisitions 6,200,000 — 6,200,000 EEH Units issued in connection with the Foreland Acquisition 2,611,111 — 2,611,111 EEH Units issued in connection with the vesting of restricted stock units 928,342 — 928,342 EEH Units and Class B Common Stock converted to Class A Common Stock 664,839 (664,839) — As of December 31, 2021 53,467,307 60.9 % 34,344,532 39.1 % 87,811,839

Net Income (Loss) Per Common Sh

Net Income (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Net Income (Loss) Per Common Share	Net Income (Loss) Per Common Share Net income (loss) per common share—basic is calculated by dividing Net income (loss) by the weighted average number of shares of common stock outstanding during the period. Net income (loss) per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income (loss) by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income (loss) per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect. A reconciliation of Net income (loss) per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2021 2020 2019 Net income (loss) attributable to Earthstone Energy, Inc. $ 35,484 $ (13,547) $ 719 Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic $ 0.75 $ (0.45) $ 0.02 Diluted $ 0.71 $ (0.45) $ 0.02 Weighted average common shares outstanding Basic 47,169,948 29,911,625 28,983,354 Add potentially dilutive securities: Unvested restricted stock units 539,803 — — Unvested performance units 2,242,342 — 377,531 Diluted weighted average common shares outstanding 49,952,093 29,911,625 29,360,885

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Common Stock	Common Stock Class A Common Stock At December 31, 2021 and 2020, there were 53,467,307 and 30,343,421 shares of Class A Common Stock issued and outstanding, respectively. During the year ended December 31, 2021, Earthstone issued a total of approximately 21.5 million shares of Class A Common Stock in connection with the IRM Acquisition, Tracker/Sequel Acquisitions and the Foreland Acquisition. No shares were issued in connection with acquisitions during 2020 or 2019. During the years ended December 31, 2021, 2020 and 2019, as a result of the vesting and settlement of restricted stock units under the Earthstone Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), Earthstone issued 1,381,825, 914,905 and 736,706 shares of Class A Common Stock, respectively, of which 453,483, 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, 2021
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, 2021, the maximum number of shares of Class A Common Stock that may be issued under the 2014 Plan was 12.0 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, 2021: Shares Weighted-Average Grant Date Fair Value Unvested RSUs at December 31, 2020 1,050,908 $ 5.55 Granted 668,000 $ 6.16 Forfeited (20,266) $ 5.09 Vested (926,825) $ 5.71 Unvested RSUs at December 31, 2021 771,817 $ 5.91 During the year ended December 31, 2021, Earthstone granted 548,000 RSUs to employees and 120,000 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, 2021, 2020 and 2019 were $4.1 million, $4.4 million and $6.5 million, respectively, with a weighted average grant date fair value per share of $6.16, $5.07 and 6.04, respectively. The total vesting date fair value of the RSUs that vested during 2021, 2020 and 2019 was $8.8 million, $3.0 million and $4.2 million, respectively. As of December 31, 2021, there was approximately $4.5 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 1.04 years. For the years ended December 31, 2021, 2020 and 2019, stock-based compensation related to RSUs was $5.2 million, $5.4 million and $5.9 million, respectively. Performance Units The table below summarizes performance unit (“PSU”) activity for the year ended December 31, 2021: Shares Weighted-Average Grant Date Fair Value Unvested PSUs at December 31, 2020 1,879,425 $ 7.65 Granted 1,099,800 $ 10.85 Vested (227,500) $ 13.75 Unvested PSUs at December 31, 2021 2,751,725 $ 8.42 The total grant date fair value of the PSUs granted during the years ended December 31, 2021, 2020 and 2019 were $11.9 million, $5.6 million and $6.2 million, respectively, with a weighted average grant date fair value per share of $10.85, $5.36 and $9.30, respectively. The total vesting date fair value of the PSUs that vested during 2021 was $3.5 million. No PSUs vested during 2020 or 2019. As of December 31, 2021, there was $16.0 million of unrecognized compensation expense related to the PSU awards which will be amortized over a weighted average period of 0.96 years. For the years ended December 31, 2021, 2020 and 2019, stock-based compensation related to the PSUs was approximately $15.8 million, $4.6 million and $2.7 million, respectively. On January 27, 2021, the Board of Directors of Earthstone (the “Board”) granted 1,099,800 PSUs (the “2021 PSUs”) to certain officers pursuant to the 2014 Plan (the “2021 Grant”). The 2021 PSUs are payable in cash or shares of Class A Common Stock upon the achievement by the Company over a period commencing on January 1, 2021 and ending on December 31, 2023 of certain performance criteria established by the Board. The Company classifies these awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards. The 2021 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, 2021. 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 20.5% or greater 2.0 14.5% 1.0 7.7% 0.5 Less than 7.7% 0.0 In the event that greater than 1.0x of the 2021 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock. The Company accounts for these awards as market-based awards which are valued quarterly 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 2021 PSUs, assuming a risk-free rate of 0.3% and volatility of 86.0%, the Company calculated the weighted average grant date fair value per PSU to be $10.85. Based on the fair value of the 2021 PSUs, the Company recorded stock-based compensation expense of $6.3 million during the year ended December 31, 2021. A corresponding liability of $6.3 million related to the 2021 PSUs is included in Other noncurrent liabilities in the Consolidated Balance Sheet as of December 31, 2021. On January 30, 2020, 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 of certain performance criteria established by the Board. The 2020 PSUs are eligible to be earned based on the annualized 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, solely at the discretion of the Board. 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. On January 28, 2019, the Board granted 669,550 PSUs (the “2019 PSUs”) to certain executive officers pursuant to the 2014 Plan. The PSUs are payable in shares of Class A Common Stock based upon the achievement by the Company over a period commencing on February 1, 2019 and ending on January 31, 2022 of performance criteria established by the Board. The number of shares of Class A Common Stock that may be issued will be determined by multiplying the number of PSUs granted by the Relative TSR Percentage (0% to 200%). The “Relative TSR Percentage” is the percentage, if any, achieved by attainment of a certain predetermined range of targets for the three-year period beginning on February 1, 2019. TSR for the Company and each of the peer companies is generally determined by dividing (A) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the last calendar day of the applicable performance period minus the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the applicable performance period plus cash dividends paid over the applicable performance period by (B) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the applicable performance period. 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 PSUs granted on January 28, 2019, assuming a risk-free rate of 2.6% and volatilities ranging from 40.1% to 114.1%, the Company calculated the weighted average grant date fair value per PSU to be $9.30. Modification of Performance Units The 2019 PSUs were initially classified as equity awards as the intention was to fully settle in shares. As of December 31, 2021, and at discretion of the Board, the 2019 PSUs in excess of 100% were to be settled in cash. This event was treated as a modification of the award with the bifurcated cash settled portion of the award being remeasured and classified as a liability award. The Company calculated the fair value of the cash settled portion of the award to be $13.66, resulting in $5.5 million additional stock-based compensation during the year ended December 31, 2021, $2.3 million of stock-based compensation previously recognized in Additional Paid-in Capital being reclassified with a corresponding liability of $7.8 million included in Accrued Expenses in the Consolidated Balance Sheet as of December 31, 2021. The 2019 PSUs were settled on February 9, 2022 resulting in the issuance of 608,125 shares of Class A Common Stock and cash payments totaling $8.1 million.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2021
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”), BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, and the Lenders party thereto (collectively, the “Parties”) entered into a credit agreement (the “Credit Agreement”), which replaced the prior credit facility, which was terminated on November 21, 2019. On December 17, 2020, Earthstone, EEH, as Borrower, Wells Fargo, as Administrative Agent, the guarantors party thereto, and the lenders party thereto (the “Lenders”) entered into an amendment (the “Second Amendment”) to the Credit Agreement. The Second Amendment was effective upon the closing of the IRM Acquisition described in Note 3. Acquisitions and Divestitures . Among other things, the Second Amendment (i) joined certain financial institutions as additional lenders, increased the borrowing base from $240.0 million to $360.0 million, (ii) increased the interest rate on outstanding borrowings; and (iii) adjusted some of the financial covenants. On April 20, 2021, the Parties entered into an amendment (the “Third Amendment”) to the Credit Agreement under which the borrowing base increased from $360 million to $475 million in connection with its regularly scheduled redetermination. Further, the Third Amendment provided for an increase in the borrowing base from $475 million to $550 million which became effective on July 20, 2021 upon closing of the Tracker/Sequel Purchase Agreements described in Note 3. Acquisitions and Divestitures . On September 17, 2021, Earthstone, EEH, as Borrower, Wells Fargo as Administrative Agent and Issuing Bank, the lenders party thereto (the “Lenders”) and the guarantors party thereto entered into an amendment (the “Fourth Amendment”) to the Credit Agreement. Among other things, the Fourth Amendment increased the borrowing base from $550 million to $650 million in connection with its regularly scheduled semi-annual redetermination, added provisions to provide for the eventual replacement of LIBOR as a benchmark interest rate, made certain changes to the lenders under the Credit Agreement, and made certain other administrative changes to the Credit Agreement. The next regularly scheduled redetermination of the borrowing base is expected to occur on or around May 1, 2022. Subsequent redeterminations are expected to 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 SOFR Rate (as customarily defined) (the “Adjusted Term SOFR Rate”) plus 2.50% to 4.25% 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 Term SOFR Rate for an interest rate period of one month plus 1.0%, (ii) plus 1.50% to 3.25%, 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. 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, (as such term is defined in the Credit Agreement) 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 (loss) for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income (loss) 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 (loss) 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 (loss), 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. As of December 31, 2021, EEH was in compliance with the covenants under the Credit Agreement. As of December 31, 2021, the Company had a $650.0 million borrowing base under the Credit Agreement, of which $320.0 million was outstanding, bearing annual interest of 3.110%, resulting in an additional $330.0 million of borrowing base availability under the Credit Agreement. At December 31, 2020, there were $115.0 million of borrowings outstanding under the Credit Agreement. For the year ended December 31, 2021, the Company had borrowings of $744.1 million and $539.1 million in repayments of borrowings.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 (in thousands) : 2021 2020 Beginning asset retirement obligations $ 3,027 $ 2,164 Associated with acquisitions 9,821 — Liabilities incurred 163 106 Property dispositions (41) (10) Liabilities settled (185) (195) Accretion expense 1,065 307 Revision of estimates 2,016 655 Ending asset retirement obligations $ 15,866 $ 3,027

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2021
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. The Audit Committee of the Board independently reviews and approves all related party transactions. Earthstone has two significant shareholders that consist of various investment funds managed by each of the two private equity firms who may manage other investments in entities with which the Company interacts in the normal course of business (the “Significant Shareholders” or separately, each a “Significant Shareholder”). 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 a 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 15. Commitments and Contingencies , a Significant Shareholder was also named in the lawsuit. As a result of a settlement agreement relating to the lawsuit, the Company agreed with its insurance carrier regarding an allocation of defense costs and settlement contributions above its deductible for all the parties named in the lawsuit. In connection with the Court approved settlement, the Significant Shareholder was billed approximately $1.1 million in fiscal 2020 and all amounts have been received. As discussed in Note 3. Acquisitions and Divestitures , on March 31, 2021, the Company entered into the Tracker/Sequel Purchase Agreements. The Tracker/Sequel Acquisitions were consummated on July 20, 2021, whereby the Company acquired the Tracker Assets for a purchase price of $18.8 million in cash and 4.7 million shares of Class A Common Stock. A Significant Shareholder owned approximately 49% of Tracker as of the closing of the Tracker Acquisition. A majority of the stockholders of Earthstone not affiliated with the Significant Shareholder approved the issuance of 6.2 million shares of Class A Common Stock in connection with the closing of the Tracker/Sequel Purchase Agreements at Earthstone’s Annual Meeting of Stockholders held on July 20, 2021. As discussed in Note 3. Acquisitions and Divestitures , during the second quarter of 2021, the Company completed the Eagle Ford Acquisitions for a purchase price of approximately $45.2 million in cash. A Significant Shareholder controlled one of the

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Contractual Commitments Future minimum contractual commitments as of December 31, 2021 under non-cancelable agreements having initial or remaining terms in excess of one year are as follows: 2022 2023 2024 2025 2026 Thereafter Office leases 696 595 605 152 — — Total $ 696 $ 595 $ 605 $ 152 $ — $ — Additionally, the Company leases corporate office space in The Woodlands, Texas and Midland, Texas. Rent expense was approximately $0.8 million, $0.8 million and $0.8 million, for the years ended December 31, 2021, 2020 and 2019, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2021 are included 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, a purported shareholder class and derivative action in the Delaware Court of Chancery was filed against Earthstone’s Chief Executive Officer, along with other members of the Board, EnCap Investments L.P. (“EnCap”), Bold Energy Holdings, LLC (“Bold Holdings”), and Bold Energy III LLC (“Bold”) and Oak Valley Resources,

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
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, 2021, 2020 and 2019 ( in thousands ): Years Ended December 31, 2021 2020 2019 Current: Federal $ — $ — $ — State (625) (545) — Total current (625) (545) — Deferred: Federal (901) 147 (95) State (333) 510 (1,570) Total deferred (1,234) 657 (1,665) Total income tax (expense) benefit $ (1,859) $ 112 $ (1,665) Effective Tax Rate A reconciliation of the effective tax rate to the federal statutory rate for the years ended December 31, 2021, 2020 and 2019 is as follows ( in thousands, except percentages ): Years Ended December 31, 2021 2020 2019 Net income (loss) before income taxes $ 63,365 $ (29,546) $ 3,245 Statutory rate 21 % 21 % 21 % Tax (expense) benefit computed at statutory rate (13,307) 6,204 (681) Noncontrolling interest 5,613 (3,349) 374 Non-deductible general and administrative expenses 455 (1,943) (230) State return to accrual — (157) (286) State income taxes, net of Federal benefit (958) (35) (1,285) Valuation allowance 6,338 (608) 443 Total income tax (expense) benefit $ (1,859) $ 112 $ (1,665) Effective tax rate (2.9) % (0.4) % (51.3) % During the year ended December 31, 2021, the Company recorded total income tax expense of $1.9 million which included (1) deferred income tax expense for Lynden US of $0.9 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $6.3 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, (3) current income tax expense of $0.63 million and (4) deferred income tax expense of $0.33 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, 2021. 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 income 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, 2021 and 2020 are as follows ( in thousands ): Years Ended December 31, 2021 2020 Deferred noncurrent income tax assets (liabilities): Oil & gas properties $ 20,909 $ 18,929 Basis difference in subsidiary obligation (2,211) (2,211) Investment in Partnerships (27,463) (25,760) Federal net operating loss carryforward 16,544 11,590 Net deferred noncurrent tax (liability) asset 7,779 2,548 Valuation allowance (23,510) (17,044) Net deferred tax liability $ (15,731) $ (14,496) As of December 31, 2021, the Company had a valuation allowance recorded against its deferred tax asset of $23.5 million which is in excess of its net deferred noncurrent tax liabilities of $7.8 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, 2021, 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 $19.7 million deferred tax asset, a $10.4 million deferred tax liability, a $3.8 million deferred tax asset and a $5.3 million deferred tax liability, respectively, before considering the valuation allowance of $23.5 million. 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 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 income tax returns, one Canadian income tax and one related to the Texas Margin Tax were 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, 2021, (1) Earthstone had estimated U.S. net operating loss carryforwards of $29.1 million, expiring in 2036 and 2037 and $14.4 million with an indefinite carryforward life (“ICL”), (2) Lynden US had estimated U.S. net operating loss carryforwards of $31.9 million, expiring from 2032 through 2037 and $2.6 million with an indefinite carryforward life, and, (3) Lynden Corp had Canadian net operating loss carryforwards of $10.0 million, the first expiring in 2024 and the last in 2037. ICL loss deductions are limited to 80% of the excess of taxable income in the year utilized. Additionally, 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 $65.9 million limited by Sec 382 resulting from the Lynden Arrangement. The Company continues to evaluate the impact, if any, of potential Sec 382 limitations. On February 15, 2022, as a result of the completion of the Chisholm Acquisition, which included the issuance of 19,417,476 shares of our Class A Common Stock, a limitation was triggered under Section 382 of the Code. The Company is currently assessing the impact of the limitation on both its NOL and its deferred tax asset. 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, 2021, 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, 2021, 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, 2021
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, 2021, 2020 and 2019 were $0.5 million, $0.5 million and $0.5 million, respectively.

Leases

Leases	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Leases	LeasesThe 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 option reasonably certain of exercise. None of the lease agreements include variable lease payments. The lease agreements do not contain any material residual value guarantees or material restrictive covenants. 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 2021 2020 Assets Noncurrent: Operating Operating lease right-of-use assets $ 1,795 $ 2,450 Finance Office and other equipment, net of accumulated depreciation and amortization — 74 Total lease assets $ 1,795 $ 2,524 Liabilities Current: Operating Operating lease liabilities $ 681 $ 773 Finance Finance lease liabilities — 69 Noncurrent: Operating Operating lease liabilities 1,276 1,840 Finance Finance lease liabilities — 5 Total lease liabilities $ 1,957 $ 2,687 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 2021 2020 2019 Operating lease expense General and administrative expense $ 803 $ 786 $ 754 Finance lease expense: Amortization of right-of-use assets Depreciation, depletion and amortization $ 74 $ 217 $ 298 Interest on lease liability Interest expense, net 2 13 33 Total lease expense $ 879 $ 1,016 $ 1,085 Additionally, the Company capitalized as part of oil and gas properties $6.4 million, $2.9 million and $11.4 million of short-term lease costs related to drilling rig contracts during the years ended December 31, 2021, 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, 2021 were as follows (in thousands) : Operating Finance 2022 $ 696 $ — 2023 595 — 2023 605 — 2025 152 — 2026 — — Thereafter — — Total lease payments $ 2,048 $ — Less imputed interest (91) — Total lease liability $ 1,957 $ — The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company’s leases as of the dates indicated: December 31, 2021 December 31, 2020 Operating Leases Finance Leases Operating Leases Finance Leases Weighted-average remaining lease term (in years) 2.9 n/a 3.9 1.0 Weighted-average discount rate (1) 4.35 % n/a 4.35 % 6.71 % (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, 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Cash payments for operating leases $ 778 $ 632 Cash payments for finance leases 70 130 Right-of-use assets obtained in exchange for new operating lease liabilities — —
Leases	LeasesThe 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 option reasonably certain of exercise. None of the lease agreements include variable lease payments. The lease agreements do not contain any material residual value guarantees or material restrictive covenants. 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 2021 2020 Assets Noncurrent: Operating Operating lease right-of-use assets $ 1,795 $ 2,450 Finance Office and other equipment, net of accumulated depreciation and amortization — 74 Total lease assets $ 1,795 $ 2,524 Liabilities Current: Operating Operating lease liabilities $ 681 $ 773 Finance Finance lease liabilities — 69 Noncurrent: Operating Operating lease liabilities 1,276 1,840 Finance Finance lease liabilities — 5 Total lease liabilities $ 1,957 $ 2,687 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 2021 2020 2019 Operating lease expense General and administrative expense $ 803 $ 786 $ 754 Finance lease expense: Amortization of right-of-use assets Depreciation, depletion and amortization $ 74 $ 217 $ 298 Interest on lease liability Interest expense, net 2 13 33 Total lease expense $ 879 $ 1,016 $ 1,085 Additionally, the Company capitalized as part of oil and gas properties $6.4 million, $2.9 million and $11.4 million of short-term lease costs related to drilling rig contracts during the years ended December 31, 2021, 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, 2021 were as follows (in thousands) : Operating Finance 2022 $ 696 $ — 2023 595 — 2023 605 — 2025 152 — 2026 — — Thereafter — — Total lease payments $ 2,048 $ — Less imputed interest (91) — Total lease liability $ 1,957 $ — The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company’s leases as of the dates indicated: December 31, 2021 December 31, 2020 Operating Leases Finance Leases Operating Leases Finance Leases Weighted-average remaining lease term (in years) 2.9 n/a 3.9 1.0 Weighted-average discount rate (1) 4.35 % n/a 4.35 % 6.71 % (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, 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Cash payments for operating leases $ 778 $ 632 Cash payments for finance leases 70 130 Right-of-use assets obtained in exchange for new operating lease liabilities — —

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2021
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event Chisholm Acquisition On February 15, 2022, Earthstone, EEH, Chisholm Energy Operating, LLC (“OpCo”) and Chisholm Energy Agent, Inc. (“Agent” and collectively with OpCo, “Chisholm”), as seller, consummated the transactions (the “Chisholm Closing”) contemplated in the Chisholm Agreement. At the closing of the Chisholm Agreement, among other things, EEH acquired (the “Chisholm Acquisition”) interests in oil and gas leases and related property of Chisholm located in Lea County and Eddy County, New Mexico, for aggregate consideration consisting of: (i) approximately $314.7 million in cash, net of preliminary and customary purchase price adjustments and remains subject to post-closing settlement between EEH and Chisholm paid at the closing of the Chisholm Acquisition, (ii) $70 million in cash to be paid as follows: $40 million to be paid six months after the closing of the Chisholm Acquisition and $30 million to be paid 12 months after the closing of the Chisholm Acquisition, subject to acceleration in the event that Earthstone receives gross proceeds of more than $450 million from a high yield bond offering or more than $50 million in gross proceeds from an offering of Class A Common Stock or preferred stock; and (iii) 19,417,476 shares of Class A Common Stock. On December 17, 2021, in accordance with the Chisholm Agreement and prior to the Chisholm Closing, Earthstone provided a deposit in the amount of $30.5 million which was recorded in Other noncurrent assets in the Consolidated Balance Sheeet as of December 31, 2021, as well as included in Acquisition of oil and gas properties in Cash flows from investing activities in the Consolidated Statements of Cash Flows for the year then ended. A Significant Shareholder was the majority owner of Chisholm as of the closing of the Chisholm Acquisition. A majority of the stockholders of Earthstone not affiliated with the Significant Shareholder approved the issuance of 19,417,476 shares of Class A Common Stock in connection with the closing of the Chisholm Acquisition. Cash consideration for the Chisholm Acquisition was funded by borrowings under the Credit Agreement whose borrowing base was increased from $650 million to $825 million at the closing of the Chisholm Acquisition on February 15, 2022. Bighorn Agreement On January 30, 2022, Earthstone, EEH, and Bighorn Asset Company, LLC, a Delaware limited liability company (“Bighorn”), as seller, entered into a Purchase and Sale Agreement (the “Bighorn Agreement”). Pursuant to the Bighorn Agreement, EEH will acquire (the “Bighorn Acquisition”) interests in oil and gas leases and related property of Bighorn located in the Midland Basin, Texas, for a purchase price (the “Bighorn Purchase Price”) of $770 million in cash and 6,808,511 shares of Class A Common Stock. The Bighorn Purchase Price is subject to customary purchase price adjustments with an effective date of January 1, 2022. In connection with the Bighorn Agreement, EEH deposited $50 million in cash into a third-party escrow account as a deposit pursuant to the Bighorn Agreement, which will be credited against the Bighorn Purchase Price upon closing of the Bighorn Acquisition. Credit Agreement On January 30, 2022, Earthstone, EEH, as Borrower, Wells Fargo Bank, National Association (“Wells Fargo”) as Administrative Agent, the lenders party thereto (the “Lenders”) and the guarantors party thereto entered into an amended and restated Fifth Amendment (the “Amendment”) to the Credit Agreement. Among other things, the Amendment increases the borrowing base and corresponding elected commitments from $650 million to $825 million upon the closing (“Chisholm Closing”) of the Chisholm Agreement; provides that upon the closing of the Bighorn Acquisition (assuming the occurrence of the Chisholm Closing), the borrowing base and corresponding elected commitments will increase to $1.325 billion, unless Earthstone completes an unsecured senior notes offering (the “Notes Offering”) prior to the closing of the Bighorn Acquisition in which case the elected commitments will be reduced by the amount of the net proceeds from a Notes Offering up to $500 million; provides for an increase in interest rates by 0.50% in the event a Notes Offering has not been completed prior to the closing of the Bighorn Acquisition; provides mechanics relating to the transition from LIBOR to a benchmark replacement rate to be effective contemporaneously with the effectiveness of the Amendment on January 30, 2022; adds certain hedging requirements relating to anticipated oil and natural gas production of the properties to be acquired pursuant to the Bighorn Acquisition; adjusts some financial covenants; redefines the limitations on certain restricted payments the Borrower may make; and makes certain administrative changes to the Credit Agreement. Securities Purchase Agreement

Supplemental Selected Quarterly

Supplemental Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Supplemental Selected Quarterly Financial Data (Unaudited)	Supplemental Selected Quarterly Financial Data (Unaudited) (In thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter 2021 Oil and gas revenues $ 75,572 $ 89,671 $ 110,384 $ 144,016 Income from operations 24,513 37,059 54,947 73,562 Net (loss) income attributable to Earthstone Energy, Inc. (5,833) (8,871) 10,418 39,770 Net (loss) income per common share attributable to Earthstone Energy, Inc.: Basic $ (0.14) $ (0.20) $ 0.21 $ 0.76 Diluted $ (0.14) $ (0.20) $ 0.20 $ 0.72 2020 Oil and gas revenues $ 45,138 $ 21,663 $ 41,047 $ 36,675 Loss from operations (60,368) (15,067) (4,484) (4,694) Net income (loss) attributable to Earthstone Energy, Inc. 16,708 (16,339) (5,445) (8,471) Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ 0.57 $ (0.55) $ (0.18) $ (0.28) 2019 Oil and gas revenues $ 40,728 $ 44,542 $ 39,204 $ 66,788 Income from operations 10,444 12,348 9,564 22,776 Net (loss) income attributable to Earthstone Energy, Inc. (17,204) 8,777 11,770 (2,624) Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ 0.60 $ 0.30 $ 0.41 $ (0.09)

Supplemental Information On Oil

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2021
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 2021, 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, 2021 2020 2019 Acquisition cost (1) : Proved $ 465,144 $ — $ (141) Unproved 43 — (125) Exploration costs: Abandonment costs — — 653 Geological and geophysical 341 298 — Development costs 134,035 67,550 210,520 Total additions $ 599,563 $ 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, 2021, 2020 and 2019, additions to oil and natural gas properties of $2.2 million, $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, 2021, 2020 and 2019, the Company had no capitalized exploratory well costs, nor capitalized 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, 2021 and 2020, are summarized below ( in thousands ): December 31, 2021 2020 Oil and gas properties, successful efforts method: Proved properties $ 1,726,019 $ 1,118,148 Accumulated impairment to proved properties (100,652) (100,652) Proved properties, net of accumulated impairments 1,625,367 1,017,496 Unproved properties 289,341 301,083 Accumulated impairment to Unproved properties (67,316) (67,316) Unproved properties, net of accumulated impairments 222,025 233,767 Land 5,382 5,382 Total oil and gas properties, net of accumulated impairments 1,852,774 1,256,645 Accumulated depreciation, depletion and amortization (395,625) (291,213) Net oil and gas properties $ 1,457,149 $ 965,432 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, 2021, 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, 2021, 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 $66.56 per barrel, $39.57 per barrel and $55.69 per barrel, respectively. The natural gas prices as of December 31, 2021, 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 $3.60 per MMBtu, $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, 2021, 2020 and 2019 averaged $30.16 per barrel, $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, 2021 being valued using prices of $65.64 per barrel, $3.01 per MMBtu and $30.16 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 NGL reserves for the years ended December 31, 2021, 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 Extensions and discoveries 7,016 49,846 6,532 21,856 Sales of minerals in place (8) (1) — (8) Purchases of minerals in place 25,114 106,539 17,103 59,973 Production (4,381) (14,505) (2,257) (9,055) Revision to previous estimates (6,756) 31,787 (2,596) (4,054) Balance - December 31, 2021 61,075 284,881 39,031 147,587 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 December 31, 2021 35,824 190,999 25,917 93,575 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 December 31, 2021 25,251 93,882 13,114 54,012 The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2021 and 2020: As of December 31, 2021 Oil Natural Gas NGLs Total Proved developed 14,011 74,702 10,137 36,598 Proved undeveloped 9,876 36,719 5,129 21,125 Total proved 23,887 111,421 15,266 57,723 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, 2021 included the following: • Extensions and discoveries. In 2021, extensions and discoveries of 21.9 MMBoe were primarily the result of successful drilling results in the Midland Basin. • Purchases of mineral in place. In 2021, the Company completed multiple acquisitions that resulted in 60.0 MMBoe in additional reserves, as disclosed above in Note 3. Acquisitions and Divestitures . • Revision to previous estimates. In 2021, the downward revisions of prior reserves of 4.1 MMBoe consisted of changes in anticipated well densities and changes in performance and other economic factors totaling 9.2 MMBoe and 5.5 MMBoe, respectively, offset by a positive revision of 10.6 MMBoe related to changes in prices. 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 were primarily the result of successful drilling results in the Midland Basin. • Revision to previous estimates. In 2020, the downward revisions of prior reserves of 10.7 MMBoe were composed of negative revisions due to the reclassification of 11.9 MMBoe of reserves from proved undeveloped to non-proved due to the SEC's five-year development rule and negative revisions of 2.7 MMBoe due to changes in price offset by revisions of 3.9 MMBoe related to changes in performance and other economic factors. 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 were primarily the result of successful drilling results in 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 in the Notes to Consolidated Financial Statements. • 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, 2021, 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 Conversions to developed (8,274) Extensions and discoveries 20,521 Purchases of minerals in place 11,577 Revision to previous estimates (10,389) Proved undeveloped reserves at December 31, 2021 (4) 54,012 (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. (4) Includes 21,125 MBoe attributable to noncontrolling interests. 2021 Changes in Proved Undeveloped Reserves Conversions to developed . In the Company's year-end 2020 plan to develop its PUDs within five years, it was estimated that $41.1 million of capital would be expended in 2021 for the conversion of 13 gross / 10.5 net PUDs to add 6.7 MMBoe. In 2021, due to improved commodity prices, the Company spent $55.1 million to convert 16 gross / 13.1 net PUDs adding 8.3 MMBoe to developed. Revision to previous estimates. Downward revisions of prior reserves of 10.4 MMBoe consisted of changes in anticipated well densities and changes in performance and other economic factors of 9.2 MMBoe and 2.9 MMBoe, respectively, offset by a positive revision of 1.7 MMBoe related to changes in prices. 2020 Changes in Proved Undeveloped Reserves Conversions to developed . In the Company's year-end 2019 plan to develop its PUDs within five years, the Company 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, the Company spent $67.8 million to convert 18 gross / 10.3 net PUDs adding 8.2 MMBoe to developed. Revision to previous estimates. The Company maintains 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 the Company's inventory of undrilled well locations. In response to lower commodity prices, the Company reduced the pace of activity in its 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 the Company's then-current acreage position, strip prices, anticipated well economics, and its development plans at the time these reserves were classified as proved, the Company's management believes 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 / 12.3 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 reserves. 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 the Company 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, 2021, 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 at December 31, 2021, 2020 and 2019 is as follows ( in thousands ): December 31, 2021 2020 2019 Future cash inflows $ 6,042,508 $ 1,902,073 $ 3,250,868 Future production costs (1,641,130) (633,248) (1,027,464) Future development costs (470,008) (285,088) (628,692) Future income tax expense (381,663) (35,557) (58,824) Future net cash flows 3,549,707 948,180 1,535,888 10% annual discount for estimated timing of cash flows (1,731,335) (487,327) (746,311) Standardized measure of discounted future net cash flows (1) $ 1,818,372 $ 460,853 $ 789,577 (1) At December 31, 2021, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $711.2 million, $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 three-year period ended December 31, 2021 ( in thousands ): December 31, 2021 2020 2019 Beginning of year $ 460,853 $ 789,577 $ 959,452 Sales of oil and gas produced, net of production costs (343,914) (105,555) (150,708) Sales of minerals in place 14 14 (458) Net changes in prices and production costs 1,346,851 (381,769) (565,240) Extensions, discoveries, and improved recoveries 216,583 14,644 127,182 Changes in income taxes, net (185,757) 17,826 12,697 Previously estimated development costs incurred during the period 41,120 66,788 210,520 Net changes in future development costs (104,223) 258,741 118,348 Purchases of minerals in place 465,187 — — Revisions of previous quantity estimates (151,748) (273,781) (35,588) Accretion of discount 76,121 81,999 107,432 Changes in timing of estimated cash flows and other (2,715) (7,631) 5,940 End of year (1) $ 1,818,372 $ 460,853 $ 789,577 (1) At December 31, 2021, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $711.2 million, $246.9 million and $430.4 million, respectively.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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 (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties. 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. The Company had no goodwill recorded in the Consolidated Balance Sheets at December 31, 2021 or 2020.
Office and Other 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 Sheets as of December 31, 2021 and 2020, as well as an adjustment to Net income in the Consolidated Statements of Operations for the years ended December 31, 2021 and 2020.
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, 2021 and 2020, amounts receivable from contracts with customers were $50.6 million and $16.3 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, 2021 or 2020. 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, 2021 and 2020, 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, 2021, two purchasers accounted for 34% and 13%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. 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, 2021, 2020 or 2019. Additionally, at December 31, 2021, three purchasers accounted for 26%, 21% and 12%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. 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. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2021 and 2020. 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, 2021, one operator distributed 13% of the Company’s oil, natural gas and natural gas liquids revenues. 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, 2021, the Company had a net derivative liability position of $44.4 million. At December 31, 2020, the Company had $6.6 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. The Company classifies grants to be settled in shares as equity awards and awards to be settled in cash a liability awards. The Company accounts for these awards 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, 2021, and includes 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, 2021 and 2020, 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
Recently Issued Accounting Standards	Recently Issued Accounting Standards 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. 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, 2021. Fair Value on a Recurring Basis Derivative Financial Instruments Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of fixed price swaps, basis swaps and costless collars 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. Share-based Compensation Liability Certain of our performance-based stock awards (“PSUs”) may be payable in cash. The Company classifies the awards that may be settled in cash as liability awards. These awards are valued quarterly 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. The inputs for the Monte Carlo model are designated as Level 2 within the valuation hierarchy. The share-based compensation liability related to the PSU liability awards is included in Accrued expenses and Other noncurrent liabilities in the Consolidated Balance Sheet as of December 31, 2021.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Schedule of Business Acquisitions, by Acquisition	The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price): Consideration: Shares of Class A Common Stock issued 12,719,594 Class A Common Stock price as of January 7, 2021 $ 6.02 Class A Common Stock consideration 76,572 Cash consideration 140,507 Total consideration transferred $ 217,079 Fair value of assets acquired: Cash $ 4,763 Other current assets 11,524 Oil and gas properties 224,112 Other non-current assets 252 Amount attributable to assets acquired $ 240,651 Fair value of liabilities assumed: Derivative liability $ 10,177 Other current liabilities 5,196 Asset retirement obligation - noncurrent 8,199 Amount attributable to liabilities assumed $ 23,572
Asset Acquisition	The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price): Total Consideration: Shares of Earthstone Class A Common Stock issued 6,200,000 Earthstone Class A Common Stock price as of July 20, 2021 $ 9.97 Class A Common Stock consideration 61,814 Cash consideration (1) 60,159 Direct transaction costs (2) 1,579 Total consideration transferred $ 123,552 Fair value of assets acquired: Oil and gas properties $ 124,152 Amount attributable to assets acquired $ 124,152 Fair value of liabilities assumed: Noncurrent liabilities - ARO 600 Amount attributable to liabilities assumed $ 600 (1) Includes customary purchase price adjustments. (2) Represents $1.6 million of transaction costs associated with the Tracker Acquisition and the Sequel Acquisition that have been capitalized in accordance with ASC 805-50.
Business Acquisition, Pro Forma Information	These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the Company for the periods presented or that may be achieved by the Company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts): Years Ended December 31, 2021 2020 Revenue $ 460,948 $ 287,359 Income (loss) before taxes 88,917 (239,752) Net income (loss) 87,058 (239,980) Less: Net income (loss) attributable to noncontrolling interest 36,833 (99,695) Net income (loss) attributable to Earthstone Energy, Inc. 50,226 (140,285) Pro forma net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic $ 1.06 $ (2.87) Diluted $ 1.01 $ (2.87)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 Level 1 Level 2 Level 3 Total Financial assets Derivative asset- current $ — $ 1,348 $ — $ 1,348 Derivative asset- noncurrent — 157 — 157 Total financial assets $ — $ 1,505 $ — $ 1,505 Financial liabilities Derivative liability - current $ — $ 45,310 $ — $ 45,310 Derivative liability - noncurrent — 571 — 571 Share-based compensation liability - noncurrent — 14,159 — 14,159 Total financial liabilities $ — $ 60,040 $ — $ 60,040 December 31, 2020 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

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021. When aggregating multiple contracts, the weighted average contract price is disclosed. Period Commodity Volume Price 2022 Crude Oil Swap 2,768,250 $57.69 2022 Crude Oil Basis Swap (1) 3,832,500 $0.51 2022 Natural Gas Swap 5,900,000 $3.20 2022 Natural Gas Basis Swap (2) 9,100,000 $(0.26) 2023 Natural Gas Swap 1,375,000 $3.27 (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. Costless Collars Period Commodity Volume Bought Floor Sold Ceiling 2022 Crude Oil Costless Collar 730,000 $60.00 $73.73 2023 Crude Oil Costless Collar 365,000 $55.00 $71.75 2022 Natural Gas Costless Collar 4,037,500 $3.43 $5.10 2023 Natural Gas Costless Collar 888,000 $3.25 $5.13
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, 2021 December 31, 2020 Derivatives not Balance Sheet Location Gross Gross Net Gross Gross Net Commodity contracts Derivative asset - current $ 3,191 $ (1,843) $ 1,348 $ 11,071 $ (3,562) $ 7,509 Commodity contracts Derivative liability - current $ 47,153 $ (1,843) $ 45,310 $ 4,492 $ (3,562) $ 930 Interest rate swaps Derivative liability - current $ — $ — $ — $ 205 $ — $ 205 Commodity contracts Derivative asset - noncurrent $ 2,721 $ (2,564) $ 157 $ 396 $ — $ 396 Commodity contracts Derivative liability - noncurrent $ 3,135 $ (2,564) $ 571 $ — $ — $ — 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 2021 2020 2019 Unrealized (loss) gain Not presented separately Not presented separately $ (40,795) $ 3,855 $ (59,849) Realized (loss) gain Operating portion of net cash received in settlement of derivative contracts Not presented separately (75,966) 56,044 15,866 Total loss (gain) on derivative contracts, net (Loss) gain on derivative contracts, net $ (116,761) $ 59,899 $ (43,983)

Noncontrolling Interest (Tables

Noncontrolling Interest (Tables)	12 Months Ended
	Dec. 31, 2021
Noncontrolling Interest [Abstract]
Summary of Changes in Noncontrolling Interest	The following table presents the changes in noncontrolling interest for the year ended December 31, 2021: EEH Units Held By Earthstone and Lynden US % EEH Units Held By Others % Total EEH Units Outstanding As of December 31, 2020 30,343,421 46.4 % 35,009,371 53.6 % 65,352,792 EEH Units issued in connection with the IRM Acquisition 12,719,594 — 12,719,594 EEH Units issued in connection with the Tracker/Sequel Acquisitions 6,200,000 — 6,200,000 EEH Units issued in connection with the Foreland Acquisition 2,611,111 — 2,611,111 EEH Units issued in connection with the vesting of restricted stock units 928,342 — 928,342 EEH Units and Class B Common Stock converted to Class A Common Stock 664,839 (664,839) — As of December 31, 2021 53,467,307 60.9 % 34,344,532 39.1 % 87,811,839

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Schedule of Reconciliation of Net Loss Per Common Share	A reconciliation of Net income (loss) per common share is as follows: Years Ended December 31, (In thousands, except per share amounts) 2021 2020 2019 Net income (loss) attributable to Earthstone Energy, Inc. $ 35,484 $ (13,547) $ 719 Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic $ 0.75 $ (0.45) $ 0.02 Diluted $ 0.71 $ (0.45) $ 0.02 Weighted average common shares outstanding Basic 47,169,948 29,911,625 28,983,354 Add potentially dilutive securities: Unvested restricted stock units 539,803 — — Unvested performance units 2,242,342 — 377,531 Diluted weighted average common shares outstanding 49,952,093 29,911,625 29,360,885

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021: Shares Weighted-Average Grant Date Fair Value Unvested RSUs at December 31, 2020 1,050,908 $ 5.55 Granted 668,000 $ 6.16 Forfeited (20,266) $ 5.09 Vested (926,825) $ 5.71 Unvested RSUs at December 31, 2021 771,817 $ 5.91 The table below summarizes performance unit (“PSU”) activity for the year ended December 31, 2021: Shares Weighted-Average Grant Date Fair Value Unvested PSUs at December 31, 2020 1,879,425 $ 7.65 Granted 1,099,800 $ 10.85 Vested (227,500) $ 13.75 Unvested PSUs at December 31, 2021 2,751,725 $ 8.42
Schedule Of Total Shareholder Return Goals	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 20.5% or greater 2.0 14.5% 1.0 7.7% 0.5 Less than 7.7% 0.0 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, 2021
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, 2021 and 2020 (in thousands) : 2021 2020 Beginning asset retirement obligations $ 3,027 $ 2,164 Associated with acquisitions 9,821 — Liabilities incurred 163 106 Property dispositions (41) (10) Liabilities settled (185) (195) Accretion expense 1,065 307 Revision of estimates 2,016 655 Ending asset retirement obligations $ 15,866 $ 3,027

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of Lessee, Operating Lease, Liability, Maturity	Future minimum contractual commitments as of December 31, 2021 under non-cancelable agreements having initial or remaining terms in excess of one year are as follows: 2022 2023 2024 2025 2026 Thereafter Office leases 696 595 605 152 — — Total $ 696 $ 595 $ 605 $ 152 $ — $ — Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2021 were as follows (in thousands) : Operating Finance 2022 $ 696 $ — 2023 595 — 2023 605 — 2025 152 — 2026 — — Thereafter — — Total lease payments $ 2,048 $ — Less imputed interest (91) — Total lease liability $ 1,957 $ —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Provision	The following table shows the components of the Company’s income tax provision for the years ended December 31, 2021, 2020 and 2019 ( in thousands ): Years Ended December 31, 2021 2020 2019 Current: Federal $ — $ — $ — State (625) (545) — Total current (625) (545) — Deferred: Federal (901) 147 (95) State (333) 510 (1,570) Total deferred (1,234) 657 (1,665) Total income tax (expense) benefit $ (1,859) $ 112 $ (1,665)
Schedule of Reconciliation of Effective Tax Rate to Statutory Rate	A reconciliation of the effective tax rate to the federal statutory rate for the years ended December 31, 2021, 2020 and 2019 is as follows ( in thousands, except percentages ): Years Ended December 31, 2021 2020 2019 Net income (loss) before income taxes $ 63,365 $ (29,546) $ 3,245 Statutory rate 21 % 21 % 21 % Tax (expense) benefit computed at statutory rate (13,307) 6,204 (681) Noncontrolling interest 5,613 (3,349) 374 Non-deductible general and administrative expenses 455 (1,943) (230) State return to accrual — (157) (286) State income taxes, net of Federal benefit (958) (35) (1,285) Valuation allowance 6,338 (608) 443 Total income tax (expense) benefit $ (1,859) $ 112 $ (1,665) Effective tax rate (2.9) % (0.4) % (51.3) %
Schedule of Components of Deferred Tax Assets and Liabilities	Significant components of the deferred tax assets and liabilities at December 31, 2021 and 2020 are as follows ( in thousands ): Years Ended December 31, 2021 2020 Deferred noncurrent income tax assets (liabilities): Oil & gas properties $ 20,909 $ 18,929 Basis difference in subsidiary obligation (2,211) (2,211) Investment in Partnerships (27,463) (25,760) Federal net operating loss carryforward 16,544 11,590 Net deferred noncurrent tax (liability) asset 7,779 2,548 Valuation allowance (23,510) (17,044) Net deferred tax liability $ (15,731) $ (14,496)

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Schedule of 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 2021 2020 Assets Noncurrent: Operating Operating lease right-of-use assets $ 1,795 $ 2,450 Finance Office and other equipment, net of accumulated depreciation and amortization — 74 Total lease assets $ 1,795 $ 2,524 Liabilities Current: Operating Operating lease liabilities $ 681 $ 773 Finance Finance lease liabilities — 69 Noncurrent: Operating Operating lease liabilities 1,276 1,840 Finance Finance lease liabilities — 5 Total lease liabilities $ 1,957 $ 2,687
Schedule of 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 2021 2020 2019 Operating lease expense General and administrative expense $ 803 $ 786 $ 754 Finance lease expense: Amortization of right-of-use assets Depreciation, depletion and amortization $ 74 $ 217 $ 298 Interest on lease liability Interest expense, net 2 13 33 Total lease expense $ 879 $ 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 as of the dates indicated: December 31, 2021 December 31, 2020 Operating Leases Finance Leases Operating Leases Finance Leases Weighted-average remaining lease term (in years) 2.9 n/a 3.9 1.0 Weighted-average discount rate (1) 4.35 % n/a 4.35 % 6.71 % (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, 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Cash payments for operating leases $ 778 $ 632 Cash payments for finance leases 70 130 Right-of-use assets obtained in exchange for new operating lease liabilities — —
Schedule of Finance Lease, Liability, Maturity	Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2021 were as follows (in thousands) : Operating Finance 2022 $ 696 $ — 2023 595 — 2023 605 — 2025 152 — 2026 — — Thereafter — — Total lease payments $ 2,048 $ — Less imputed interest (91) — Total lease liability $ 1,957 $ —
Schedule of Lessee, Operating Lease, Liability, Maturity	Future minimum contractual commitments as of December 31, 2021 under non-cancelable agreements having initial or remaining terms in excess of one year are as follows: 2022 2023 2024 2025 2026 Thereafter Office leases 696 595 605 152 — — Total $ 696 $ 595 $ 605 $ 152 $ — $ — Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2021 were as follows (in thousands) : Operating Finance 2022 $ 696 $ — 2023 595 — 2023 605 — 2025 152 — 2026 — — Thereafter — — Total lease payments $ 2,048 $ — Less imputed interest (91) — Total lease liability $ 1,957 $ —

Supplemental Selected Quarter_2

Supplemental Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Selected Quarterly Financial Data	(In thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter 2021 Oil and gas revenues $ 75,572 $ 89,671 $ 110,384 $ 144,016 Income from operations 24,513 37,059 54,947 73,562 Net (loss) income attributable to Earthstone Energy, Inc. (5,833) (8,871) 10,418 39,770 Net (loss) income per common share attributable to Earthstone Energy, Inc.: Basic $ (0.14) $ (0.20) $ 0.21 $ 0.76 Diluted $ (0.14) $ (0.20) $ 0.20 $ 0.72 2020 Oil and gas revenues $ 45,138 $ 21,663 $ 41,047 $ 36,675 Loss from operations (60,368) (15,067) (4,484) (4,694) Net income (loss) attributable to Earthstone Energy, Inc. 16,708 (16,339) (5,445) (8,471) Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ 0.57 $ (0.55) $ (0.18) $ (0.28) 2019 Oil and gas revenues $ 40,728 $ 44,542 $ 39,204 $ 66,788 Income from operations 10,444 12,348 9,564 22,776 Net (loss) income attributable to Earthstone Energy, Inc. (17,204) 8,777 11,770 (2,624) Net income (loss) per common share attributable to Earthstone Energy, Inc.: Basic and diluted $ 0.60 $ 0.30 $ 0.41 $ (0.09)

Supplemental Information On O_2

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Extractive Industries [Abstract]
Schedule of Costs Incurred in Oil and Gas Producing Activities	The Company’s oil and natural gas activities for 2021, 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, 2021 2020 2019 Acquisition cost (1) : Proved $ 465,144 $ — $ (141) Unproved 43 — (125) Exploration costs: Abandonment costs — — 653 Geological and geophysical 341 298 — Development costs 134,035 67,550 210,520 Total additions $ 599,563 $ 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, 2021 and 2020, are summarized below ( in thousands ): December 31, 2021 2020 Oil and gas properties, successful efforts method: Proved properties $ 1,726,019 $ 1,118,148 Accumulated impairment to proved properties (100,652) (100,652) Proved properties, net of accumulated impairments 1,625,367 1,017,496 Unproved properties 289,341 301,083 Accumulated impairment to Unproved properties (67,316) (67,316) Unproved properties, net of accumulated impairments 222,025 233,767 Land 5,382 5,382 Total oil and gas properties, net of accumulated impairments 1,852,774 1,256,645 Accumulated depreciation, depletion and amortization (395,625) (291,213) Net oil and gas properties $ 1,457,149 $ 965,432
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 NGL reserves for the years ended December 31, 2021, 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 Extensions and discoveries 7,016 49,846 6,532 21,856 Sales of minerals in place (8) (1) — (8) Purchases of minerals in place 25,114 106,539 17,103 59,973 Production (4,381) (14,505) (2,257) (9,055) Revision to previous estimates (6,756) 31,787 (2,596) (4,054) Balance - December 31, 2021 61,075 284,881 39,031 147,587 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 December 31, 2021 35,824 190,999 25,917 93,575 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 December 31, 2021 25,251 93,882 13,114 54,012 The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2021 and 2020: As of December 31, 2021 Oil Natural Gas NGLs Total Proved developed 14,011 74,702 10,137 36,598 Proved undeveloped 9,876 36,719 5,129 21,125 Total proved 23,887 111,421 15,266 57,723 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
Schedule of Changes in PUD Reserves	Changes in PUD reserves for the years ended December 31, 2021, 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 Conversions to developed (8,274) Extensions and discoveries 20,521 Purchases of minerals in place 11,577 Revision to previous estimates (10,389) Proved undeveloped reserves at December 31, 2021 (4) 54,012 (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. (4) Includes 21,125 MBoe attributable to noncontrolling interests.
Schedule Of Standardized Measure	The Standardized Measure at December 31, 2021, 2020 and 2019 is as follows ( in thousands ): December 31, 2021 2020 2019 Future cash inflows $ 6,042,508 $ 1,902,073 $ 3,250,868 Future production costs (1,641,130) (633,248) (1,027,464) Future development costs (470,008) (285,088) (628,692) Future income tax expense (381,663) (35,557) (58,824) Future net cash flows 3,549,707 948,180 1,535,888 10% annual discount for estimated timing of cash flows (1,731,335) (487,327) (746,311) Standardized measure of discounted future net cash flows (1) $ 1,818,372 $ 460,853 $ 789,577 (1) At December 31, 2021, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $711.2 million, $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 three-year period ended December 31, 2021 ( in thousands ): December 31, 2021 2020 2019 Beginning of year $ 460,853 $ 789,577 $ 959,452 Sales of oil and gas produced, net of production costs (343,914) (105,555) (150,708) Sales of minerals in place 14 14 (458) Net changes in prices and production costs 1,346,851 (381,769) (565,240) Extensions, discoveries, and improved recoveries 216,583 14,644 127,182 Changes in income taxes, net (185,757) 17,826 12,697 Previously estimated development costs incurred during the period 41,120 66,788 210,520 Net changes in future development costs (104,223) 258,741 118,348 Purchases of minerals in place 465,187 — — Revisions of previous quantity estimates (151,748) (273,781) (35,588) Accretion of discount 76,121 81,999 107,432 Changes in timing of estimated cash flows and other (2,715) (7,631) 5,940 End of year (1) $ 1,818,372 $ 460,853 $ 789,577 (1) At December 31, 2021, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $711.2 million, $246.9 million and $430.4 million, respectively.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2020USD ($)	Dec. 31, 2021USD ($)segment$ / shares	Dec. 31, 2020USD ($)$ / shares	Dec. 31, 2019USD ($)
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts receivable		$ 20,000	$ 20,000
Goodwill		0	0
Impairment of goodwill	$ 17,600,000	0	17,620,000	$ 0
Office and other equipment, net		2,000,000	900,000
Accumulated depreciation and amortization		4,547,000	3,675,000
Depreciation expense		$ 700,000	500,000	$ 700,000
Number of reportable segment | segment		1
Receivables from contracts with customers		$ 50,600,000	16,300,000
Net derivative asset (liability)		$ (44,400,000)	$ 6,600,000
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 | Customer One
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk		34.00%	32.00%	30.00%
Customer Concentration Risk | Sales Revenue, Net | Customer Two
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk		13.00%	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 | Customer One
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk		26.00%	18.00%
Customer Concentration Risk | Accounts Receivable | Customer Two
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk		21.00%	17.00%
Customer Concentration Risk | Accounts Receivable | Customer Three
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk		12.00%	16.00%
Distributor Concentration Risk | Sales Revenue, Net | Major Operator One
Summary Of Significant Accounting Policies [Line Items]
Percentage of concentration risk		13.00%	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.		60.90%
Bold Energy Holdings, LLC | Earthstone Energy Holdings, LLC | Bold Contribution Agreement
Summary Of Significant Accounting Policies [Line Items]
Percentage of ownership interest		39.10%

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details) $ / shares in Units, $ in Thousands	Nov. 02, 2021USD ($)shares	Jul. 20, 2021USD ($)shares	Jan. 07, 2021USD ($)$ / sharesshares	Jun. 30, 2021USD ($)seller	Dec. 31, 2021USD ($)	Sep. 30, 2021USD ($)seller	Dec. 31, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Business Acquisition [Line Items]
Transaction costs								$ 4,875		$ 622	$ 1,077
Proceeds from sale of oil and gas properties								975		414	4,184
Gain on sale of oil and gas properties, net								$ 738		204	3,222
Non-core Properties
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties											4,200
Gain on sale of oil and gas properties, net											$ 3,600
Tracker Acquisition
Business Acquisition [Line Items]
Payments to acquire assets, net of purchase price adjustments		$ 18,800
Shares of earthstone class A common stock issued (in shares) | shares		4,700,000
Cash consideration		$ 18,800
Tracker Acquisition | Significant Shareholder
Business Acquisition [Line Items]
Asset acquisition, percentage of voting interest acquired					49.00%		49.00%	49.00%	49.00%
Sequel Purchase Agreement
Business Acquisition [Line Items]
Shares of earthstone class A common stock issued (in shares) | shares		1,500,000
Cash consideration		$ 41,400
Tracker And Sequel Acquisitions
Business Acquisition [Line Items]
Asset acquisition pro forma revenue							$ 40,500
Asset acquisition pro forma operating expenses							$ 11,500
Foreland Acquisition
Business Acquisition [Line Items]
Shares of earthstone class A common stock issued (in shares) | shares	2,611,111
Cash consideration	$ 16,300
BCC Acquisition
Business Acquisition [Line Items]
Cash consideration	$ 23,000
Class A Common Stock | Tracker Acquisition
Business Acquisition [Line Items]
Shares of earthstone class A common stock issued (in shares) | shares		4,700,000
Class A Common Stock | Tracker And Sequel Acquisitions
Business Acquisition [Line Items]
Shares of earthstone class A common stock issued (in shares) | shares		6,200,000
IRM Acquisition
Business Acquisition [Line Items]
Net cash consideration			$ 140,500
Pro forma revenue									$ 95,100
Pro forma operating expense									$ 44,400
Transaction costs					$ 4,000			$ 4,000		$ 1,000
Total consideration transferred			$ 217,079
IRM Acquisition | Class A Common Stock
Business Acquisition [Line Items]
Shares issued (in shares) | shares			12,719,594
Acquisition shares price (in dollars per share) | $ / shares			$ 6.02
Eagle Ford Acquisitions
Business Acquisition [Line Items]
Business combination, number of separate sellers | seller				4		4
Total consideration transferred				$ 45,200		$ 45,200

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Consideration Transferred In Business Combination (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 20, 2021	Jan. 07, 2021
Fair value of liabilities assumed:
Other current liabilities		$ 5,196
Tracker And Sequel Acquisitions
Fair value of liabilities assumed:
Transaction costs	$ 1,579
IRM Acquisition
Business Acquisition [Line Items]
Cash consideration		140,507
Total consideration transferred		217,079
Fair value of assets acquired:
Cash		4,763
Other current assets		11,524
Oil and gas properties		224,112
Other non-current assets		252
Amount attributable to assets acquired		240,651
Fair value of liabilities assumed:
Derivative liability		10,177
Asset retirement obligation - noncurrent		8,199
Amount attributable to liabilities assumed		$ 23,572
IRM Acquisition | Class A Common Stock
Business Acquisition [Line Items]
Shares of Class A Common Stock issued (in shares)		12,719,594
Class A Common Stock price (in dollars per share)		$ 6.02
Class A Common Stock consideration		$ 76,572

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Consideration Transferred In Asset Acquisition (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 20, 2021	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Noncurrent liabilities - ARO		$ 163	$ 106
Tracker And Sequel Acquisitions
Business Acquisition [Line Items]
Payments for asset acquisitions	$ 60,159
Transaction costs	1,579
Total consideration transferred	123,552
Oil and gas properties	124,152
Asset Acquisition, Assets Acquired	124,152
Noncurrent liabilities - ARO	600
Amount attributable to liabilities assumed	$ 600
Tracker And Sequel Acquisitions | Class A Common Stock
Business Acquisition [Line Items]
Shares of earthstone class A common stock issued (in shares)	6,200,000
Earthstone Class A Common Stock price (in dollars per share)	$ 9.97
Class A Common Stock consideration	$ 61,814

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Combination and Asset Acquisition [Abstract]
Revenue	$ 460,948	$ 287,359
Income (loss) before taxes	88,917	(239,752)
Net income (loss)	87,058	(239,980)
Less: Net income (loss) attributable to noncontrolling interest	36,833	(99,695)
Net income (loss) attributable to Earthstone Energy, Inc.	$ 50,226	$ (140,285)
Basic (in dollars per share)	$ 1.06	$ (2.87)
Diluted (in dollars per share)	$ 1.01	$ (2.87)

Transaction Costs (Details)

Transaction Costs (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Transaction costs		$ 4,875	$ 622	$ 1,077
IRM Acquisition
Business Acquisition [Line Items]
Transaction costs	$ 4,000	4,000	1,000
Other Potential Transactions
Business Acquisition [Line Items]
Transaction costs		300	300
Bold Transaction
Business Acquisition [Line Items]
Payments for reimbursement of expenses		1,200	$ 700
Chisholm Acquisition
Business Acquisition [Line Items]
Transaction costs		$ 1,800

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Financial assets
Derivative asset- current	$ 1,348	$ 7,509
Derivative asset- noncurrent	157	396
Financial liabilities
Derivative liability - current	45,310	1,135
Derivative liability - noncurrent	571	173
Fair Value on a Recurring Basis
Financial assets
Derivative asset- current	1,348	7,509
Derivative asset- noncurrent	157	396
Total financial assets	1,505	7,905
Financial liabilities
Derivative liability - current	45,310	1,135
Derivative liability - noncurrent	571	173
Share-based compensation liability - noncurrent	14,159
Total financial liabilities	60,040	1,308
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
Share-based compensation liability - noncurrent	0
Total financial liabilities	0	0
Level 2 | Fair Value on a Recurring Basis
Financial assets
Derivative asset- current	1,348	7,509
Derivative asset- noncurrent	157	396
Total financial assets	1,505	7,905
Financial liabilities
Derivative liability - current	45,310	1,135
Derivative liability - noncurrent	571	173
Share-based compensation liability - noncurrent	14,159
Total financial liabilities	60,040	1,308
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
Share-based compensation liability - noncurrent	0
Total financial liabilities	$ 0	$ 0

Derivative Financial Instrume_3

Derivative Financial Instruments - Schedule of Open Crude Oil and Natural Gas Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2021MMBTUBoe$ / bbl$ / MMBTUMMcfbbl
Derivative Swap Contractual Period One, 2022 | Crude Oil
Derivative [Line Items]
Crude oil volume (Bbl) | bbl	2,768,250
Weighted average price ($/Bbl / $/MMBtu) | $ / bbl	57.69
Crude Oil Basis Swap, Swap One, 2022 | Crude Oil
Derivative [Line Items]
Crude oil volume (Bbl) | bbl	3,832,500
Weighted average price ($/Bbl / $/MMBtu) | $ / bbl	0.51
Natural Gas Swap Period One, 2022 | Natural Gas (MMcf)
Derivative [Line Items]
Crude oil volume (Bbl) | bbl	5,900,000
Weighted average price ($/Bbl / $/MMBtu) | $ / bbl	3.20
Natural Gas Basis Swap Period One, 2022 | Natural Gas (MMcf)
Derivative [Line Items]
Natural gas volume (MMBtu) | MMBTU	9,100,000
Weighted average price ($/Bbl / $/MMBtu)	(0.26)
Natural Gas Swap Period Two, 2023 | Natural Gas (MMcf)
Derivative [Line Items]
Natural gas volume (MMBtu) | MMBTU	1,375,000
Weighted average price ($/Bbl / $/MMBtu)	3.27
Crude Oil Costless Collar One, 2022 | Crude Oil
Derivative [Line Items]
Crude oil volume (Bbl) | MMcf	730,000
Derivative, floor price ($/Bbl / $/MMBtu) | $ / MMBTU	60
Derivative, ceiling price ($/Bbl / $/MMBtu) | $ / MMBTU	73.73
Crude Oil Costless Collar Two, 2023 | Crude Oil
Derivative [Line Items]
Crude oil volume (Bbl) | MMcf	365,000
Derivative, floor price ($/Bbl / $/MMBtu) | $ / MMBTU	55
Derivative, ceiling price ($/Bbl / $/MMBtu) | $ / MMBTU	71.75
Natural Gas Costless Collar Contractual Period One, 2022 | Natural Gas (MMcf)
Derivative [Line Items]
Natural gas volume (MMBtu) | Boe	4,037,500
Derivative, floor price ($/Bbl / $/MMBtu) | $ / MMBTU	3.43
Derivative, ceiling price ($/Bbl / $/MMBtu) | $ / MMBTU	5.10
Natural Gas Costless Collar Contractual Period Two, 2023 | Natural Gas (MMcf)
Derivative [Line Items]
Natural gas volume (MMBtu) | Boe	888,000
Derivative, floor price ($/Bbl / $/MMBtu) | $ / MMBTU	3.25
Derivative, ceiling price ($/Bbl / $/MMBtu) | $ / MMBTU	5.13

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, 2021	Dec. 31, 2020
Derivative asset - current | Commodity contracts
Derivatives, Fair Value [Line Items]
Gross recognized assets	$ 3,191	$ 11,071
Gross Amounts Offset	(1,843)	(3,562)
Total financial assets	1,348	7,509
Derivative liability - current | Commodity contracts
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	47,153	4,492
Gross Amounts Offset	(1,843)	(3,562)
Total financial liabilities	45,310	930
Derivative liability - current | Interest rate swaps
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	0	205
Gross Amounts Offset	0	0
Total financial liabilities	0	205
Derivative asset - noncurrent | Commodity contracts
Derivatives, Fair Value [Line Items]
Gross recognized assets	2,721	396
Gross Amounts Offset	(2,564)	0
Total financial assets	157	396
Derivative liability - noncurrent | Commodity contracts
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	3,135	0
Gross Amounts Offset	(2,564)	0
Total financial liabilities	571	0
Derivative liability - noncurrent | Interest rate swaps
Derivatives, Fair Value [Line Items]
Gross recognized liabilities	0	173
Gross Amounts Offset	0	0
Total financial liabilities	$ 0	$ 173

Derivative Financial Instrume_5

Derivative Financial Instruments - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Interest rate swaps
Derivative [Line Items]
Payment received from unwinding derivative	$ 1.1

Derivative Financial Instrume_6

Derivative Financial Instruments - Summary of Realized and Unrealized Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Realized (loss) gain	$ 75,966	$ (56,044)	$ (15,866)
(Loss) gain on commodity contracts, net	(116,761)	59,899	(43,983)
Derivatives Not Designated as Hedging Contracts | (Loss) Gain On Derivative Contracts, Net
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (loss) gain	(40,795)	3,855	(59,849)
Realized (loss) gain	$ (75,966)	$ 56,044	$ 15,866

Oil and Natural Gas Properties

Oil and Natural Gas Properties - Narrative (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil And Natural Gas Properties [Line Items]
Impairment expense	$ 2,000,000	$ 2,100,000	$ 42,800,000	$ 0		$ 0
Accumulated impairments to proved and unproved oil and natural gas properties	$ 168,000,000			168,000,000	$ 168,000,000
Proved Oil and Natural Gas Properties
Oil And Natural Gas Properties [Line Items]
Depletion expenses				$ 105,700,000	95,900,000	$ 68,500,000
Impairment expense					25,300,000
Unproved Oil and Gas Properties
Oil And Natural Gas Properties [Line Items]
Impairment expense					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
Unproved Oil and Gas Properties | Eagle Ford Trend Properties
Oil And Natural Gas Properties [Line Items]
Impairment expense					$ 13,200,000

Noncontrolling Interest - Summa

Noncontrolling Interest - Summary of Changes in Noncontrolling Interest (Details) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Outstanding, beginning balance (in shar	30,343,421
EEH Units issued in connection with acquisition (in shares)		0	0
Outstanding, ending balance (in shares)	53,467,307	30,343,421
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Outstanding, beginning balance (in shar	65,352,792
Outstanding, ending balance (in shares)	87,811,839	65,352,792
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Class B Common Stock converted to Class A Common Stock (in shares)	0
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | Restricted Stock Units
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH units issued in connection with the vesting of restricted stock units (in shares)	928,342
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | IRM Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	12,719,594
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | Foreland Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	2,611,111
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | Tracker/Sequel Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	6,200,000
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Outstanding, beginning balance (in shar	30,343,421
Outstanding, ending balance (in shares)	53,467,307	30,343,421
Percentage of EEH units held by Earthstone and Lynden	60.90%	46.40%
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US | Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Class B Common Stock converted to Class A Common Stock (in shares)	664,839
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US | Restricted Stock Units
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH units issued in connection with the vesting of restricted stock units (in shares)	928,342
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US | IRM Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	12,719,594
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US | Foreland Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	2,611,111
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Earthstone and Lynden US | Tracker/Sequel Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	6,200,000
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Others
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Outstanding, beginning balance (in shar	35,009,371
Outstanding, ending balance (in shares)	34,344,532	35,009,371
Percentage of EEH units held by others	39.10%	53.60%
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Others | Class A Common Stock
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Class B Common Stock converted to Class A Common Stock (in shares)	664,839
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Others | Restricted Stock Units
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH units issued in connection with the vesting of restricted stock units (in shares)	0
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Others | IRM Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	0
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Others | Foreland Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	0
Earthstone Energy Holdings, LLC | Earthstone Energy Holdings, LLC | EEH Units Held By Others | Tracker/Sequel Acquisition
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
EEH Units issued in connection with acquisition (in shares)	0

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	3 Months Ended												12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share [Abstract]
Net income (loss) attributable to Earthstone Energy, Inc.	$ 39,770	$ 10,418	$ (8,871)	$ (5,833)	$ (8,471)	$ (5,445)	$ (16,339)	$ 16,708	$ (2,624)	$ 11,770	$ 8,777	$ (17,204)	$ 35,484	$ (13,547)	$ 719
Net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic (in dollars per share)	$ 0.76	$ 0.21	$ (0.20)	$ (0.14)	$ (0.28)	$ (0.18)	$ (0.55)	$ 0.57	$ (0.09)	$ 0.41	$ 0.30	$ 0.60	$ 0.75	$ (0.45)	$ 0.02
Diluted (in dollars per share)	$ 0.72	$ 0.20	$ (0.20)	$ (0.14)	$ (0.28)	$ (0.18)	$ (0.55)	$ 0.57	$ (0.09)	$ 0.41	$ 0.30	$ 0.60	$ 0.71	$ (0.45)	$ 0.02
Weighted average common shares outstanding
Basic (in shares)													47,169,948	29,911,625	28,983,354
Add potentially dilutive securities:
Unvested restricted stock units (in shares)													539,803	0	0
Unvested performance units (in shares)													2,242,342	0	377,531
Diluted weighted average common shares outstanding (in shares)													49,952,093	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, 2021	Dec. 31, 2020	Dec. 31, 2019
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) attributable to noncontrolling interest	$ 26,000,000	$ (15,900,000)	$ 900,000
Dilutive securities, effect on earnings per share	$ 0
Restricted Stock Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Dilutive securities, effect on earnings per share		1,100,000
Performance Shares
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Dilutive securities, effect on earnings per share		$ 1,900,000
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, 2021	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)	53,467,307	30,343,421
Common stock, shares outstanding (in shares)	53,467,307	30,343,421
Shares issued in connection with acquisition (in shares)		0	0
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)			736,706
Treasury shares acquired (in shares)	453,483	243,924	203,394
Class B Common Stock
Capital Unit [Line Items]
Common stock, shares issued (in shares)	34,344,532	35,009,371
Common stock, shares outstanding (in shares)	34,344,532	35,009,371
Class B common stock converted to class A common stock (in shares)	664,839	251,309	191,498
Earthstone Energy, Inc. | Class A Common Stock
Capital Unit [Line Items]
Common stock shares issued upon completion of public offering (in shares)	1,381,825	914,905
IRM Acquisition, Tracker/Sequel Acquisitions and Foreland Acquisition | Class A Common Stock
Capital Unit [Line Items]
Shares issued in connection with acquisition (in shares)	21,500,000

Stock-Based Compensation - Narr

Stock-Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 09, 2022	Jan. 27, 2021	Jan. 30, 2020	Jan. 28, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense					$ 9,132	$ 10,054	$ 8,648
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shareholder return percentage				0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shareholder return percentage				200.00%
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)					668,000
Shares granted, weighted average grant date fair value (in dollars per share)					$ 6.16
Weighted average grant date fair value (in dollars per share)					$ 5.91	$ 5.55
Shares vested (in shares)					926,825
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)					1,099,800
Grant date fair value of units granted					$ 11,900	$ 5,600	$ 6,200
Shares granted, weighted average grant date fair value (in dollars per share)					$ 10.85	$ 5.36	$ 9.30
Vesting date fair value of units vested					$ 3,500
Stock-based compensation expense					$ 6,300
Compensation cost not yet recognized, period for recognition					11 months 15 days
Relative total shareholder return, percentage					100.00%	100.00%
Risk free interest rate				2.60%	0.30%	1.40%
Expected volatility rate					86.00%	62.00%
Weighted average grant date fair value (in dollars per share)					$ 8.42	$ 7.65
Deferred compensation share-based arrangements, liability, classified					$ 6,300
Shares vested (in shares)					227,500	0	0
Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Relative total shareholder return, percentage					0.00%
Expected volatility rate				40.10%
Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Relative total shareholder return, percentage					200.00%
Expected volatility rate				114.10%
2019 Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense					$ 5,500
Percentage of awards to be settled in cash					100.00%
Fair value of awards to be settled in cash (in dollars per share)					$ 13.66
Stock-based compensation expense					$ (2,300)
Liability for awards to be settled in cash					$ 7,800
2019 Performance Share Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vested (in shares)	608,125
Cash paid to settle awards	$ 8,100
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)					12,000,000
Grant date fair value of units granted					$ 4,100	$ 4,400	$ 6,500
Shares granted, weighted average grant date fair value (in dollars per share)					$ 6.16	$ 5.07	$ 6.04
Vesting date fair value of units vested					$ 8,800	$ 3,000	$ 4,200
Unrecognized compensation expense related to unvested stock					$ 4,500
Weighted average remaining vesting period of unrecognized compensation expense					1 year 14 days
Stock-based compensation expense					$ 5,200	5,400	5,900
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)					548,000
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)					120,000
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 Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		1,099,800	1,043,800	669,550
Stock-based compensation expense					$ 15,800	$ 4,600	$ 2,700
Compensation not yet recognized, share-based awards other than options					$ 16,000
Weighted average grant date fair value (in dollars per share)				$ 9.30	$ 10.85	$ 5.36

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Unvested RSU Award Activity (Details) - Restricted Stock Units	12 Months Ended
	Dec. 31, 2021$ / sharesshares
Shares
Beginning period (in shares) | shares	1,050,908
Granted (shares) | shares	668,000
Forfeited (in shares) | shares	(20,266)
Vested (shares) | shares	(926,825)
End period (in shares) | shares	771,817
Weighted-Average Grant Date Fair Value
Beginning of period (in dollars per share) | $ / shares	$ 5.55
Granted (in dollars per share) | $ / shares	6.16
Forfeited (in dollars per share) | $ / shares	5.09
Vested (in dollars per share) | $ / shares	5.71
End of period (in dollars per share) | $ / shares	$ 5.91

Stock-Based Compensation - Su_2

Stock-Based Compensation - Summary of Unvested PSU Award Activity (Details) - Performance Shares - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Shares
Beginning period (in shares)	1,879,425
Shares granted (in shares)	1,099,800
Shares Vested (in shares)	(227,500)	0	0
End period (in shares)	2,751,725	1,879,425
Weighted-Average Grant Date Fair Value
Beginning of period (in dollars per share)	$ 7.65
Granted (in dollars per share)	10.85	$ 5.36	$ 9.30
Vested (in dollars per share)	13.75
End of period (in dollars per share)	$ 8.42	$ 7.65

Stock-Based Compensation - TSR

Stock-Based Compensation - TSR Multiplier (Details) - Performance Shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Minimum | 20.5% or greater
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	20.50%	23.90%
Minimum | 0.145
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	14.50%	14.50%
Minimum | 0.077
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	7.70%	8.40%
Maximum | 20.5% or greater
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR Multiplier	200.00%	200.00%
Maximum | 0.145
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR Multiplier	100.00%	100.00%
Maximum | 0.077
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR Multiplier	50.00%	50.00%
Maximum | Less than 7.7%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earthstone’s Annualized TSR	7.70%	8.40%
TSR Multiplier	0.00%	0.00%

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	Nov. 21, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Sep. 17, 2021	Sep. 16, 2021	Jul. 20, 2021	Jul. 19, 2021	Apr. 20, 2021	Apr. 19, 2021	Dec. 17, 2020	Dec. 16, 2020
Debt Instrument [Line Items]
Long-term debt		$ 320,000,000	$ 115,000,000
Long-term debt, percentage bearing annual interest rate		3.11%
Commitment fees on borrowings		$ 900,000	600,000	$ 700,000
Amortization of deferred financing costs		856,000	322,000	$ 412,000
EEH Credit Agreement
Debt Instrument [Line Items]
Current borrowing base under EEH credit agreement		650,000,000			$ 650,000,000	$ 550,000,000	$ 550,000,000	$ 475,000,000	$ 475,000,000	$ 360,000,000	$ 360,000,000	$ 240,000,000
Covenant terms, minimum current ratio	1
Covenant terms, maximum leverage ratio	3.5
Long-term debt		320,000,000	$ 115,000,000
Additional borrowing base available under credit agreement		330,000,000
Amount of borrowings		744,100,000
Repayments of borrowings		$ 539,100,000
Averaged interest rate on outstanding debt		3.40%	2.83%	4.42%
Amortization of deferred financing costs		$ 900,000	$ 300,000	$ 400,000
Capitalized costs associated with borrowings		$ 2,800,000	$ 0	$ 1,600,000
EEH Credit Agreement | Minimum
Debt Instrument [Line Items]
Applicable margin percentage	1.50%
Commitment fee percentage	0.375%
EEH Credit Agreement | Maximum
Debt Instrument [Line Items]
Applicable margin percentage	3.25%
Commitment fee percentage	0.50%
EEH Credit Agreement | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Debt Instrument [Line Items]
Applicable margin percentage	1.00%
EEH Credit Agreement | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Minimum
Debt Instrument [Line Items]
Applicable margin percentage	2.50%
EEH Credit Agreement | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Maximum
Debt Instrument [Line Items]
Applicable margin percentage	4.25%
EEH Credit Agreement | Federal Funds Rate
Debt Instrument [Line Items]
Applicable margin percentage	0.50%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 3,027	$ 2,164
Associated with acquisitions	9,821	0
Liabilities incurred	163	106
Property dispositions	(41)	(10)
Liabilities settled	(185)	(195)
Accretion expense	1,065	307	$ 214
Revision of estimates	2,016	655
Ending asset retirement obligations	$ 15,866	$ 3,027	$ 2,164

Related Party Transactions (Det

Related Party Transactions (Details)	Feb. 15, 2023USD ($)	Feb. 15, 2022USD ($)	Jul. 20, 2021USD ($)shares	Feb. 12, 2020USD ($)	Jun. 30, 2021USD ($)seller	Sep. 30, 2021USD ($)seller	Aug. 15, 2022USD ($)	Dec. 31, 2021USD ($)shareholder	Dec. 17, 2021USD ($)
Related Party Transaction [Line Items]
Number of significant shareholders | shareholder								2
Proceeds form sale of oil and gas leases				$ 400,000
Forecast
Related Party Transaction [Line Items]
Payments for asset acquisitions	$ 30,000,000
Subsequent Event
Related Party Transaction [Line Items]
Consideration received on sale of stock		$ 450,000,000
Eagle Ford Acquisitions
Related Party Transaction [Line Items]
Total consideration transferred					$ 45,200,000	$ 45,200,000
Business combination, number of separate sellers | seller					4	4
Eagle Ford, Seller One
Related Party Transaction [Line Items]
Total consideration transferred						$ 8,200,000
Chisholm Acquisition
Related Party Transaction [Line Items]
Escrow deposit									$ 30,500,000
Chisholm Acquisition | Forecast
Related Party Transaction [Line Items]
Payments for asset acquisitions	$ 30,000,000						$ 40,000,000
Chisholm Acquisition | Subsequent Event
Related Party Transaction [Line Items]
Payments for asset acquisitions		70,000,000
Consideration received on sale of stock		450,000,000
Chisholm Acquisition | Subsequent Event | EEH Credit Agreement
Related Party Transaction [Line Items]
Cash consideration		314,700,000
Class A Common Stock | Subsequent Event
Related Party Transaction [Line Items]
Consideration received on sale of stock		50,000,000
Class A Common Stock | Chisholm Acquisition | Subsequent Event
Related Party Transaction [Line Items]
Consideration received on sale of stock		50,000,000
Shares issued (in shares)		19,417,476
Convertible Preferred Stock | Subsequent Event
Related Party Transaction [Line Items]
Consideration received on sale of stock		50,000,000
Convertible Preferred Stock | Chisholm Acquisition | Subsequent Event
Related Party Transaction [Line Items]
Consideration received on sale of stock		$ 50,000,000
Tracker Acquisition
Related Party Transaction [Line Items]
Cash consideration			$ 18,800,000
Shares of earthstone class A common stock issued (in shares) | shares			4,700,000
Tracker Acquisition | Significant Shareholder
Related Party Transaction [Line Items]
Asset acquisition, percentage of voting interest acquired								49.00%
Tracker Acquisition | Class A Common Stock
Related Party Transaction [Line Items]
Shares of earthstone class A common stock issued (in shares) | shares			4,700,000
Tracker And Sequel Acquisitions
Related Party Transaction [Line Items]
Payments for asset acquisitions			$ 60,159,000
Tracker And Sequel Acquisitions | Class A Common Stock
Related Party Transaction [Line Items]
Shares of earthstone class A common stock issued (in shares) | shares			6,200,000
Insurance Settlement | Settled Litigation
Related Party Transaction [Line Items]
Settlement reimbursement								$ 1,100,000

Commitments and Contingencies -

Commitments and Contingencies - Future Minimum Contractual Commitments under Non-cancelable Agreements (Details) $ in Thousands	Dec. 31, 2021USD ($)
Operating Leased Assets [Line Items]
2022	$ 696
2023	595
2024	605
2025	152
2026	0
Thereafter	0
Office leases
Operating Leased Assets [Line Items]
2022	696
2023	595
2024	605
2025	152
2026	0
Thereafter	0
Non-Cancelable Agreement
Operating Leased Assets [Line Items]
2022	696
2023	595
2024	605
2025	152
2026	0
Thereafter	$ 0

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Apr. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Loss Contingencies [Line Items]
Lease operating expense			$ 49,321	$ 29,131	$ 28,683
Settled Litigation
Loss Contingencies [Line Items]
Estimated reimbursement from insurance carriers			1,300
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%
Accrued settlement agreement costs		$ 3,500
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
Texas
Loss Contingencies [Line Items]
Lease operating expense			$ 800	$ 800	$ 800

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current:
Federal	$ 0	$ 0	$ 0
State	(625)	(545)	0
Total current	(625)	(545)	0
Deferred:
Federal	(901)	147	(95)
State	(333)	510	(1,570)
Total deferred	(1,234)	657	(1,665)
Total income tax (expense) benefit	$ (1,859)	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Net income (loss) before income taxes	$ 63,365	$ (29,546)	$ 3,245
Statutory rate	21.00%	21.00%	21.00%
Tax (expense) benefit computed at statutory rate	$ (13,307)	$ 6,204	$ (681)
Noncontrolling interest	5,613	(3,349)	374
Non-deductible general and administrative expenses	455	(1,943)	(230)
State return to accrual	0	(157)	(286)
State income taxes, net of Federal benefit	(958)	(35)	(1,285)
Valuation allowance	6,338	(608)	443
Total income tax (expense) benefit	$ (1,859)	$ 112	$ (1,665)
Effective tax rate	(2.90%)	(0.40%)	(51.30%)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	Feb. 15, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Line Items]
Income tax (expense) benefit		$ (1,859)	$ 112	$ (1,665)
Deferred income tax expense (benefit)		1,234	(657)	1,665
Current income tax expense (benefit)		625	545	$ 0
Valuation allowance		23,510	17,044
Net deferred noncurrent tax assets		7,800	2,500
Deferred tax liabilities		15,731	$ 14,496
Class A Common Stock
Income Tax Disclosure [Line Items]
EEH Units issued in connection with acquisition (in shares)			0	0
U.S.
Income Tax Disclosure [Line Items]
Deferred tax assets		19,700	$ 13,300
Deferred tax liabilities		10,400	9,600
Operating loss carryforward, net		29,100
Operating loss carryforward, not subject to expiration		14,400
Canada
Income Tax Disclosure [Line Items]
Deferred tax assets		3,800	3,800
Deferred tax liabilities		5,300	4,800
Lynden Arrangement | U.S.
Income Tax Disclosure [Line Items]
Operating loss carryforward, net		65,900
Chisholm Acquisition | Class A Common Stock | Subsequent Event
Income Tax Disclosure [Line Items]
EEH Units issued in connection with acquisition (in shares)	19,417,476
Lynden U S A Inc
Income Tax Disclosure [Line Items]
Deferred income tax expense (benefit)		900	(150)	$ 100
Lynden U S A Inc | U.S.
Income Tax Disclosure [Line Items]
Operating loss carryforward, net		31,900
Operating loss carryforward, not subject to expiration		2,600
Lynden U S A Inc | Canada
Income Tax Disclosure [Line Items]
Operating loss carryforward, net		10,000
Earthstone Energy Holdings, LLC
Income Tax Disclosure [Line Items]
Deferred income tax expense (benefit)		6,300	(610)	400
Earthstone Energy Holdings, LLC | Texas Margin Tax
Income Tax Disclosure [Line Items]
Deferred income tax expense (benefit)		$ 330	$ (510)	$ 1,600

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred noncurrent income tax assets (liabilities):
Oil & gas properties	$ 20,909	$ 18,929
Basis difference in subsidiary obligation	(2,211)	(2,211)
Investment in Partnerships	(27,463)	(25,760)
Federal net operating loss carryforward	16,544	11,590
Net deferred noncurrent tax (liability) asset	7,779	2,548
Valuation allowance	(23,510)	(17,044)
Net deferred tax liability	$ (15,731)	$ (14,496)

Defined Contribution Plan (Deta

Defined Contribution Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	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	$ 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, 2021USD ($)option	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Number of renewal terms | option	1
Short-term lease cost | $	$ 6.4	$ 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, 2021	Dec. 31, 2020
Assets and Liabilities, Lessee [Abstract]
Operating lease right-of-use assets	$ 1,795	$ 2,450
Finance lease right-of-use assets	0	74
Total lease assets	1,795	2,524
Operating Lease, Liability [Abstract]
Operating lease liability, current	681	773
Operating lease liability, noncurrent	1,276	1,840
Finance Lease Liability [Abstract]
Finance lease liability, current	0	69
Finance lease liability, noncurrent	0	5
Total lease liabilities	$ 1,957	$ 2,687
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Office and other equipment, net of accumulated depreciation of $4,547 and $3,675 at December 31, 2021 and 2020, respectively	Office and other equipment, net of accumulated depreciation of $4,547 and $3,675 at December 31, 2021 and 2020, respectively

Leases - Consolidated Statement

Leases - Consolidated Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating lease expense	$ 49,321	$ 29,131	$ 28,683
Total lease expense	879	1,016	1,085
General and administrative expense
Lessee, Lease, Description [Line Items]
Operating lease expense	803	786	754
Depreciation, depletion and amortization
Lessee, Lease, Description [Line Items]
Amortization of right-of-use assets	74	217	298
Interest expense, net
Lessee, Lease, Description [Line Items]
Interest on lease liability	$ 2	$ 13	$ 33

Leases - Schedule of Future Min

Leases - Schedule of Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2021USD ($)
Operating
2022	$ 696
2023	595
2023	605
2025	152
2026	0
Thereafter	0
Total lease payments	2,048
Less imputed interest	(91)
Total lease liability	1,957
Finance
2022	0
2023	0
2023	0
2025	0
2026	0
Thereafter	0
Total lease payments	0
Less imputed interest	0
Total lease liability	$ 0

Leases - Weighted Average Remai

Leases - Weighted Average Remaining Lease Term (Details)	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease, weighted average lease term	2 years 10 months 24 days	3 years 10 months 24 days
Operating lease, weighted average discount rate	4.35%	4.35%
Finance lease, weighted average lease term		1 year
Finance lease, weighted average discount rate		6.71%

Leases - Quantitative Lease Inf

Leases - Quantitative Lease Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Cash payments for operating leases	$ 778	$ 632
Cash payments for finance leases	70	130
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 0	$ 0

Subsequent Event - Narrative (D

Subsequent Event - Narrative (Details)

Feb. 15, 2023USD ($)

Feb. 15, 2022USD ($)

Jan. 30, 2022USD ($)numberOfCustomer$ / sharesshares

Jun. 30, 2022USD ($)shares

Aug. 15, 2022USD ($)

Dec. 31, 2021USD ($)$ / shares

Dec. 17, 2021USD ($)

Sep. 17, 2021USD ($)

Sep. 16, 2021USD ($)

Jul. 20, 2021USD ($)

Jul. 19, 2021USD ($)

Apr. 20, 2021USD ($)

Apr. 19, 2021USD ($)

Dec. 31, 2020$ / shares

Dec. 17, 2020USD ($)

Dec. 16, 2020USD ($)

Business Acquisition [Line Items]

Preferred stock, par value (in dollars per share) | $ / shares

$ 0.001

$ 0.001

Forecast

Business Acquisition [Line Items]

Payments for asset acquisitions

$ 30,000,000

EEH Credit Agreement

Business Acquisition [Line Items]

Current borrowing base under EEH credit agreement

$ 650,000,000

$ 650,000,000

$ 550,000,000

$ 550,000,000

$ 475,000,000

$ 475,000,000

$ 360,000,000

$ 360,000,000

$ 240,000,000

EEH Credit Agreement | Forecast

Business Acquisition [Line Items]

Line of credit facility, maximum borrowing capacity

$ 1,325,000,000

Potential increase (decrease) in maximum borrowing capacity

$ 500,000,000

Increase in interest rate on outstanding borrowings

0.50%

Subsequent Event

Business Acquisition [Line Items]

Consideration received on sale of stock

$ 450,000,000

Subsequent Event | EnCap

Business Acquisition [Line Items]

Number of directors employed by related party | numberOfCustomer

2

Subsequent Event | Securities Purchase Agreement | EnCap And Affiliates

Business Acquisition [Line Items]

Sale of stock, percentage of ownership after transaction

46.50%

Subsequent Event | EEH Credit Agreement

Business Acquisition [Line Items]

Current borrowing base under EEH credit agreement

825,000,000

Class A Common Stock | Subsequent Event

Business Acquisition [Line Items]

Consideration received on sale of stock

50,000,000

Class A Common Stock | Subsequent Event | Securities Purchase Agreement

Business Acquisition [Line Items]

Convertible preferred stock, conversion ratio

90.0900900900901

Sale of stock, price per share (in shares) | $ / shares

$ 11.10

Convertible Preferred Stock | Subsequent Event

Business Acquisition [Line Items]

Consideration received on sale of stock

50,000,000

Convertible Preferred Stock | Subsequent Event | Securities Purchase Agreement

Business Acquisition [Line Items]

Sale of stock (in shares) | shares

280,000

Preferred stock, par value (in dollars per share) | $ / shares

$ 0.001

Consideration received on sale of stock

$ 280,000,000

Sale of stock, price per share (in shares) | $ / shares

$ 1,000

Chisholm Acquisition

Business Acquisition [Line Items]

Escrow deposit

$ 30,500,000

Chisholm Acquisition | Forecast

Business Acquisition [Line Items]

Payments for asset acquisitions

$ 30,000,000

$ 40,000,000

Chisholm Acquisition | Subsequent Event

Business Acquisition [Line Items]

Payments for asset acquisitions

70,000,000

Consideration received on sale of stock

450,000,000

Chisholm Acquisition | Subsequent Event | EEH Credit Agreement

Business Acquisition [Line Items]

Cash consideration

314,700,000

Chisholm Acquisition | Class A Common Stock | Subsequent Event

Business Acquisition [Line Items]

Shares issued (in shares)

19,417,476

Consideration received on sale of stock

50,000,000

Chisholm Acquisition | Convertible Preferred Stock | Subsequent Event

Business Acquisition [Line Items]

Consideration received on sale of stock

$ 50,000,000

Bighorn Agreement | Subsequent Event

Business Acquisition [Line Items]

Escrow deposit

$ 50,000,000

Bighorn Agreement | Subsequent Event | Forecast

Business Acquisition [Line Items]

Cash consideration

$ 770,000,000

Shares issued (in shares) | shares

6,808,511

Supplemental Selected Quarter_3

Supplemental Selected Quarterly Financial Data (Unaudited) - Schedule of Supplemental Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Oil and gas revenues	$ 144,016	$ 110,384	$ 89,671	$ 75,572	$ 36,675	$ 41,047	$ 21,663	$ 45,138	$ 66,788	$ 39,204	$ 44,542	$ 40,728	$ 419,643	$ 144,523	$ 191,262
Income from operations	73,562	54,947	37,059	24,513	(4,694)	(4,484)	(15,067)	(60,368)	22,776	9,564	12,348	10,444	190,081	(84,613)	55,132
Net income (loss) attributable to Earthstone Energy, Inc.	$ 39,770	$ 10,418	$ (8,871)	$ (5,833)	$ (8,471)	$ (5,445)	$ (16,339)	$ 16,708	$ (2,624)	$ 11,770	$ 8,777	$ (17,204)	$ 35,484	$ (13,547)	$ 719
Net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic (in dollars per share)	$ 0.76	$ 0.21	$ (0.20)	$ (0.14)	$ (0.28)	$ (0.18)	$ (0.55)	$ 0.57	$ (0.09)	$ 0.41	$ 0.30	$ 0.60	$ 0.75	$ (0.45)	$ 0.02
Diluted (in dollars per share)	$ 0.72	$ 0.20	$ (0.20)	$ (0.14)	$ (0.28)	$ (0.18)	$ (0.55)	$ 0.57	$ (0.09)	$ 0.41	$ 0.30	$ 0.60	$ 0.71	$ (0.45)	$ 0.02

Supplemental Selected Quarter_4

Supplemental Selected Quarterly Financial Data (Unaudited) - Narrative (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Impairment expense	$ 2,000,000	$ 2,100,000	$ 42,800,000	$ 0		$ 0
Impairment of goodwill			$ 17,600,000	$ 0	$ 17,620,000	$ 0

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Acquisition cost:
Proved	$ 465,144	$ 0	$ (141)
Unproved	43	0	(125)
Exploration costs:
Abandonment costs	0	0	653
Geological and geophysical	341	298	0
Development costs	134,035	67,550	210,520
Total additions	$ 599,563	$ 67,848	$ 210,907

Supplemental Information On O_4

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Narrative (Detail) MMBTU in Thousands, Boe in Thousands, $ in Thousands, MBoe in Millions	12 Months Ended
	Dec. 31, 2021MMBTU	Dec. 31, 2021USD ($)MMBTU	Dec. 31, 2021MMBTU$ / bbl	Dec. 31, 2021MMBTU$ / MMBTU	Dec. 31, 2021MMBTUBoe	Dec. 31, 2021MMBTUMBoe	Dec. 31, 2020USD ($)MMBTUBoeMBoe$ / bbl$ / MMBTU	Dec. 31, 2019USD ($)Boe$ / bbl$ / MMBTU
Reserve Quantities [Line Items]
Additions to oil and gas properties | $		$ 599,563					$ 67,848	$ 210,907
Natural gas liquids prices used to value reserves | $ / bbl			30.16				11.61	16.17
Oil prices used to value reserves (in dollars per barrel) | $ / bbl			65.64
Natural gas prices used to value reserves (in dollars per MMBtu) | $ / MMBTU				3.01
Natural gas liquids prices used to value reserves (in dollars per barrel) | $ / bbl			30.16
Proved extensions and discoveries					21,856		860	5,065
Revision to previous estimates					(4,054)		(10,691)	(4,642)
Changes in performance					9,200
Other economic factors					5,500
Positive revision					1,700	10.6
Reclassifications					9,200		11,900
Revisions due to change in price							(2,700)
Changes in reserve due to performance and other economic factors | MBoe							3.9
Sales of minerals in place					8			32
Conversion period of proved undeveloped reserves into proved developed producing reserves	5 years						5 years	5 years
Estimated capital expenditures of proved undeveloped reserves | $		41,100					$ 111,100	$ 103,800
Estimated proved undeveloped reserves, conversions to developed, gross					13,000		28,000	30,000
Estimated proved undeveloped reserves, conversions to developed, net					10,500		17,600	12,300
Estimated conversion of proved undeveloped reserves into proved developed producing reserves					6,700		11,300	9,900
Capital expenditures of proved undeveloped reserves | $		$ 55,100					$ 67,800	$ 111,500
Modified proved undeveloped reserves, conversions to developed, gross					16,000		18,000	32,000
Modified proved undeveloped reserves, conversions to developed, net					13,100		10,300	13,400
Modified conversion of proved undeveloped reserves into proved developed producing reserves					8,300		8,200	10,300
Changes in price offset by revisions					2,900
Development plan							5 years
Remaining revisions of proved undeveloped previous estimate energy							2,100
Extensions and discoveries					20,521			1,230
Revisions					10,389		14,038	3,362
Non-Cancelable Agreement
Reserve Quantities [Line Items]
Holding pipeline capacity | MMBTU	10	10	10	10	10	10	10
Midland Basin
Reserve Quantities [Line Items]
Proved extensions and discoveries					21,900
Henry Hub Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of natural gas | $ / MMBTU				3.60			1.99	2.58
West Texas Intermediate Spot Price
Reserve Quantities [Line Items]
Unweighted average of first of the month prices of oil | $ / bbl			66.56				39.57	55.69
New Wells
Reserve Quantities [Line Items]
Additions to oil and gas properties | $		$ 2,200					$ 800	$ 100
Operated Eagle Ford and Non-operated Bakken Properties
Reserve Quantities [Line Items]
Proved extensions and discoveries							860	5,100

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, 2021	Dec. 31, 2020
Oil and gas properties, successful efforts method:
Accumulated impairment to proved\Unproved properties	$ (168,000)	$ (168,000)
Proved properties, net of accumulated impairments	1,625,367	1,017,496
Unproved properties, net of accumulated impairments	222,025	233,767
Land	5,382	5,382
Total oil and gas properties, net of accumulated impairments	1,852,774	1,256,645
Accumulated depreciation, depletion and amortization	(395,625)	(291,213)
Net oil and gas properties	1,457,149	965,432
Proved property
Oil and gas properties, successful efforts method:
Proved properties	1,726,019	1,118,148
Accumulated impairment to proved\Unproved properties	(100,652)	(100,652)
Proved properties, net of accumulated impairments	1,625,367	1,017,496
Unproved property
Oil and gas properties, successful efforts method:
Accumulated impairment to proved\Unproved properties	(67,316)	(67,316)
Unproved properties	289,341	301,083
Unproved properties, net of accumulated impairments	$ 222,025	$ 233,767

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) bbl in Thousands, MMcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2021BoebblMMcf	Dec. 31, 2020BoebblMMcf	Dec. 31, 2019BoeMMcfbbl	Dec. 31, 2018BoebblMMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | Boe	78,875	94,336	98,847
Extensions and discoveries | Boe	21,856	860	5,065
Sales of minerals in place | Boe	(8)		(32)
Purchases of minerals in place | Boe	59,973
Production | Boe	(9,055)	(5,630)	(4,902)
Revision to previous estimates | Boe	(4,054)	(10,691)	(4,642)
Ending Balance | Boe	147,587	78,875	94,336
Proved developed reserves: | Boe	93,575	38,298	31,521	23,646
Proved undeveloped reserves: | Boe	54,012	40,577	62,815	75,201
Oil (MBbl)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	40,090	52,650	59,034
Extensions and discoveries	7,016	420	3,598
Sales of minerals in place	(8)		(31)
Purchases of minerals in place	25,114
Production	(4,381)	(3,180)	(3,086)
Revision to previous estimates	(6,756)	(9,800)	(6,865)
Ending balance	61,075	40,090	52,650
Proved developed reserves:	35,824	18,878	18,220	14,325
Proved undeveloped reserves:	25,251	21,212	34,430	44,709
Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	111,215	107,990	113,217
Extensions and discoveries | MMcf	49,846	1,258	4,476
Sales of minerals in place | MMcf	(1)		(4)
Purchases of minerals in place | MMcf	106,539
Production | MMcf	(14,505)	(7,282)	(4,760)
Revision to previous estimates | MMcf	31,787	9,249	(4,939)
Ending Balance | MMcf	284,881	111,215	107,990
Proved developed reserves: | MMcf	190,999	55,764	35,120	26,110
Proved undeveloped reserves: | MMcf	93,882	55,450	72,870	87,107
NGLs (MBbl)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	20,249	23,688	20,943
Extensions and discoveries	6,532	230	721
Sales of minerals in place	0		(1)
Purchases of minerals in place	17,103
Production	(2,257)	(1,237)	(1,022)
Revision to previous estimates	(2,596)	(2,432)	3,047
Ending balance	39,031	20,249	23,688
Proved developed reserves:	25,917	10,125	7,447	4,969
Proved undeveloped reserves:	13,114	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) bbl in Thousands, MMcf in Thousands, Boe in Thousands	Dec. 31, 2021BoeMMcfbbl	Dec. 31, 2020BoeMMcfbbl	Dec. 31, 2019BoebblMMcf
Reserve Quantities [Line Items]
Proved developed | Boe	36,598	20,516	17,183
Proved undeveloped | Boe	21,125	21,737	34,243
Total proved | Boe	57,723	42,253	51,426
Oil (MBbl)
Reserve Quantities [Line Items]
Proved developed reserves, net attributable to noncontrolling interest, volume	14,011	10,113	9,933
Proved undeveloped reserves, net attributable to noncontrolling interest, volume	9,876	11,363	18,769
Proved developed and undeveloped reserves, net attributable to noncontrolling interest, volume	23,887	21,476	28,702
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Proved developed reserves, net attributable to noncontrolling interest, gas | MMcf	74,702	29,873	19,146
Proved undeveloped reserves, net attributable to noncontrolling interest, gas | MMcf	36,719	29,704	39,724
Proved developed and undeveloped reserves, net attributable to noncontrolling interest, gas | MMcf	111,421	59,577	58,870
NGLs (MBbl)
Reserve Quantities [Line Items]
Proved developed reserves, net attributable to noncontrolling interest, volume	10,137	5,424	4,060
Proved undeveloped reserves, net attributable to noncontrolling interest, volume	5,129	5,423	8,853
Proved developed and undeveloped reserves, net attributable to noncontrolling interest, volume	15,266	10,847	12,913

Supplemental Information On O_8

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited) - Schedule of Changes in Proved Undeveloped Reserves (Details) - Boe Boe in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Proved undeveloped reserves, Beginning Balance	40,577	62,815	75,201
Conversions to developed	(8,274)	(8,200)	(10,254)
Extensions and discoveries	20,521		1,230
Purchases of minerals in place	11,577
Revision to previous estimates	(10,389)	(14,038)	(3,362)
Proved undeveloped reserves, Ending Balance	54,012	40,577	62,815
Proved undeveloped reserve attributable to noncontrolling interests	21,125	21,737	34,243	41,560

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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Future cash inflows	$ 6,042,508	$ 1,902,073	$ 3,250,868
Future production costs	(1,641,130)	(633,248)	(1,027,464)
Future development costs	(470,008)	(285,088)	(628,692)
Future income tax expense	(381,663)	(35,557)	(58,824)
Future net cash flows	3,549,707	948,180	1,535,888
10% annual discount for estimated timing of cash flows	(1,731,335)	(487,327)	(746,311)
Standardized measure of discounted future net cash flows	1,818,372	460,853	789,577	$ 959,452
Standardized measure of discounted future net cash flows attributable to noncontrolling interests	$ 711,200	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 460,853	$ 789,577	$ 959,452
Sales of oil and gas produced, net of production costs	(343,914)	(105,555)	(150,708)
Sales of minerals in place	14	14	(458)
Net changes in prices and production costs	1,346,851	(381,769)	(565,240)
Extensions, discoveries, and improved recoveries	216,583	14,644	127,182
Changes in income taxes, net	(185,757)	17,826	12,697
Previously estimated development costs incurred during the period	41,120	66,788	210,520
Net changes in future development costs	(104,223)	258,741	118,348
Purchases of minerals in place	465,187	0	0
Revisions of previous quantity estimates	(151,748)	(273,781)	(35,588)
Accretion of discount	76,121	81,999	107,432
Changes in timing of estimated cash flows and other	(2,715)	(7,631)	5,940
Standardized measure, end of year	1,818,372	460,853	789,577
Standardized measure of discounted future net cash flows attributable to noncontrolling interests	$ 711,200	$ 246,900	$ 430,400

Uncategorized Items - este-2021

Label	Element	Value
Accounting Standards Update [Extensible Enumeration]	us-gaap_AccountingStandardsUpdateExtensibleList	Accounting Standards Update 2018-01 [Member]