10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2015

Or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 001-35049  

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	84-0592823
(State or other jurisdiction	(I.R.S Employer
of incorporation or organization)	Identification No.)

1400 Woodloch Forest Drive, Suite 300

The Woodlands, Texas 77380

(Address of principal executive offices)

Registrant’s telephone number, including area code:  (281) 298-4246

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days.    Yes  þ    No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to post such filed).     Yes  þ    No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  þ

As of November 6, 2015, 13,835,128 shares of common stock, $0.001 par value per share, were outstanding.

TABLE OF CONTENTS

		Page
	PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)	5
	Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	5
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014	6
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	7
	Notes to Unaudited Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 4.	Controls and Procedures	27
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
Item 3.	Defaults Upon Senior Securities	29
Item 4.	Mine Safety Disclosures	29
Item 6.	Exhibits	29
	Signatures	30

2

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals or prospects are also forward-looking statements. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section included in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2014, and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

· volatility and weakness in commodity prices for oil and natural gas and the effect of prices set or influenced by action of the Organization of Petroleum Exporting Countries (“OPEC”);

· changes in estimates of our proved reserves;

· our ability to replace our oil and natural gas reserves;

· declines in the values of our oil and natural gas reserves;

· the potential for production decline rates for our wells to be greater than we expect;

· the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves; 

· the ability and willingness of our partners under our joint operating agreements to join in our future exploration, development and production activities;

· our ability to acquire leases, supplies and services on a timely basis and at reasonable prices;

· the cost and availability of goods and services, such as drilling rigs and completion equipment;

· risks in connection with potential acquisitions and the integration of significant acquisitions;

· the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and will divert management’s time and energy;

· the possibility that anticipated divestitures may not occur or could be burdened with unforeseen costs;

· reductions in the borrowing base under our credit facility;

· risks incident to the drilling and operation of oil and natural gas wells;

· the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

· the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on prices;

· significant competition for acreage and acquisitions, including competition which may be intense in resources play areas pending adequate commodity prices and reserve potential;

· the effect of existing and future laws, governmental regulations and the political and economic climates of the United States;

· our ability to attract and retain key members of senior management and key technical employees;

· changes in environmental laws and the regulation and enforcement related to those laws;

· the identification of and severity of environmental events and governmental responses to these or other environmental events;

· legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulations, derivatives reform, and changes in state, and federal income taxes;

· general economic conditions, whether internationally, nationally or in the regional and local market areas in which we conduct  business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets will be disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;

3

· social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as Africa, the Middle East, and armed conflict or acts of terrorism or sabotage;

· the insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;

· other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

· the effect of our oil and natural gas derivative activities;

· title to the properties in which we have an interest may be impaired by title defects; and

· our dependency on the skill, ability and decisions of third party operators of oil and natural gas properties in which we have a non-operated working interest.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

4

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

	September 30,			December 31,
ASSETS	2015			2014
Current assets:	(In thousands, except share amounts)
Cash and cash equivalents	$	41,327		$	100,447
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues		15,828			14,016
Joint interest billings and other		6,370			9,417
Prepaid expenses and other current assets		1,058			1,578
Current derivative assets		3,626			3,569
Total current assets		68,209			129,027
Oil and gas properties, successful efforts method:
Proved properties		365,584			317,006
Unproved properties		85,971			76,791
Total oil and gas properties		451,555			393,797
Accumulated depreciation, depletion, and amortization		(111,530	)		(97,920	)
Net oil and gas properties		340,025			295,877
Other noncurrent assets:
Goodwill		22,992			22,992
Office and other equipment, less accumulated depreciation of $879 and $474 at    September 30, 2015 and December 31, 2014		2,032			2,109
Land		101			101
Noncurrent derivative assets		287			—
Other noncurrent assets		1,184			1,282
TOTAL ASSETS	$	434,830		$	451,388
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	23,662		$	28,753
Accrued expenses		16,454			20,529
Revenues and royalties payable		9,947			17,364
Advances		21,600			21,398
Asset retirement obligations		341			408
Total current liabilities		72,004			88,452
Noncurrent liabilities:
Long-term debt		11,191			11,191
Asset retirement obligations		5,822			5,670
Deferred tax liability		29,188			29,258
Other noncurrent liabilities		241			289
Total noncurrent liabilities		46,442			46,408
Total liabilities		118,446			134,860
Commitments and Contingencies (Note 10)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized;    none issued or outstanding		—			—
Common stock, $0.001 par value, 100,000,000 shares authorized; 13,835,128 shares    issued and outstanding at September 30, 2015 and December 31, 2014		14			14
Additional paid-in capital		358,086			358,086
Accumulated deficit		(41,256	)		(41,112	)
Treasury stock, 15,414 shares at September 30, 2015 and December 31, 2014		(460	)		(460	)
Total equity		316,384			316,528
TOTAL LIABILITIES AND EQUITY	$	434,830		$	451,388

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Threemonths ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
REVENUES	(In thousands, except share and per share amounts)
Oil, natural gas, and natural gas liquids revenues:
Oil	$	10,385		$	8,916		$	31,586		$	25,292
Natural gas		1,971			2,113			5,483			7,459
Natural gas liquids		677			928			2,164			2,842
Total oil, natural gas, and natural gas liquids revenues		13,033			11,957			39,233			35,593
Gathering income		60			98			233			293
(Loss) gain on sales of oil and gas properties, net		(13	)		—			1,667			—
Total revenues		13,080			12,055			41,133			35,886
OPERATING COSTS AND EXPENSES
Production costs:
Lease operating expense		4,138			2,536			12,751			7,210
Severance taxes		746			481			2,122			1,479
Re-engineering and workovers		234			234			520			553
Exploration expense		—			83			142			83
Depreciation, depletion, and amortization		8,107			5,268			22,705			13,031
General and administrative expense		2,450			1,602			7,505			4,816
Total operating costs and expenses		15,675			10,204			45,745			27,172
(Loss) income from operations		(2,595	)		1,851			(4,612	)		8,714
OTHER INCOME (EXPENSE)
Interest expense, net		(169	)		(149	)		(507	)		(446	)
Net gain on derivative contracts		5,166			2,489			4,522			186
Other income, net		127			23			384			30
Total other income (expense)		5,124			2,363			4,399			(230	)
Income (loss) before income taxes		2,529			4,214			(213	)		8,484
Income tax expense (benefit)		811			—			(69	)		—
Net income (loss)	$	1,718		$	4,214		$	(144	)	$	8,484
Net income (loss) per common share:
Basic	$	0.12		$	0.46		$	(0.01	)	$	0.93
Diluted	$	0.12		$	0.46		$	(0.01	)	$	0.93
Weighted average common shares outstanding:
Basic		13,835,128			9,124,452			13,835,128			9,124,452
Diluted		13,835,128			9,124,452			13,835,128			9,124,452

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine months ended September 30,
	2015			2014
Cash flows from operating activities:	(In thousands)
Net (loss) income	$	(144	)	$	8,484
Adjustments to reconcile net (loss) income to net cash provided by    operating activities:
Depreciation, depletion, and amortization		22,705			13,031
Unrealized gain on derivative contracts		(344	)		(1,155	)
Accretion of asset retirement obligations		425			229
Deferred income taxes		(69	)		—
Amortization of deferred financing costs		195			113
Settlement of asset retirement obligations		(65	)		(56	)
Gain on sale of assets		(1,667	)		—
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		5,362			(18,457	)
Decrease (increase) in prepaid expenses and other		548			(408	)
(Decrease) increase in accounts payable and accrued expenses		(15,547	)		38,532
(Decrease) increase in revenue and royalties payable		(7,318	)		10,509
Increase in advances		224			11,028
Net cash provided by operating activities		4,305			61,850
Cash flows from investing activities:
Acquisitions of oil and gas property		(8,706	)		—
Additions to oil and gas property and equipment		(57,705	)		(54,537	)
Additions to other property and equipment		(328	)		(576	)
Proceeds from sales of oil and gas properties		3,441			—
Net cash used in investing activities		(63,298	)		(55,113	)
Cash flows from financing activities:
Deferred financing costs		(127	)		(188	)
Net cash used in financing activities		(127	)		(188	)
Net (decrease) increase in cash and cash equivalents		(59,120	)		6,549
Cash and cash equivalents at beginning of period		100,447			25,423
Cash and cash equivalents at end of period	$	41,327		$	31,972
Supplemental disclosure of cash flow information
Cash paid for:
Interest	$	284		$	331
Non-cash investing and financing activities:
Asset retirement obligations	$	128		$	50
Acquisitions of oil and gas properties	$	2,130		$	—

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Basis of Presentation

Earthstone Energy, Inc., a Delaware corporation (“Earthstone” or the “Company”) is an independent oil and gas exploration and production company engaged in the acquisition, development, exploration and production of onshore, unconventional reserves, with a current focus on the Eagle Ford trend of South Texas and the Bakken trend of North Dakota and Montana. The Company also has conventional wells in East Texas, South Texas and Oklahoma.

The accompanying unaudited consolidated financial statements of Earthstone and our wholly-owned subsidiaries, which we refer to as “we,” “our” or “us,” have been prepared in accordance with Article 8-03 of Regulation S-X for interim financial statements required to be filed with the Securities and Exchange Commission (“SEC”).  The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's Condensed Consolidated Balance Sheets as of September 30, 2015, and December 31, 2014; the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014; and the Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014.  The Company’s balance sheet at December 31, 2014 is derived from the audited consolidated financial statements at that date.

The preparation of financial statements in conformity with the generally accepted accounting principles of the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. For further information, see Note 2 in the Notes to Consolidated Financial Statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014.

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements and the accompanying notes prepared in accordance with GAAP, has been condensed or omitted. These financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and the Company’s other filings with the SEC.  The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

On December 19, 2014, the Company acquired three operating subsidiaries of Oak Valley Resources, LLC (“OVR”), in exchange for shares of Earthstone common stock (the “Exchange”), which resulted in a change of control of the Company. Pursuant to the Exchange Agreement, OVR contributed to Earthstone the membership interests of its three subsidiaries, Oak Valley Operating, LLC (“OVO”), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”), in exchange for approximately 9.124 million shares, representing 84% of the Company’s common stock.  The transaction was accounted for as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes.  All historical financial information, prior to December 19, 2014, contained in this Quarterly Report on Form 10-Q is that of Oak Valley.

Immediately following the Exchange, the Company, through its acquired wholly owned subsidiary, Sabine, acquired an additional 20% undivided ownership interest in certain crude oil and gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of approximately 2.957 million shares of common stock (the “Contribution Agreement”) to Flatonia Energy, LLC, increasing the Company’s ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest.  As a result of the share issuance to Flatonia, OVR’s ownership in the Company decreased from 84% to 66%.

Recently Issued Accounting Standards

Revenue Recognition - In May 2014, the Financial Accounting Standards Board (“FASB”) issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its consolidated financial statements.

8

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements.  Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset.  Amortization of the costs is reported as interest expense.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  The Company will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods.  The Company does not expect the adoption of this new presentation guidance to have a material impact on its consolidated balance sheets.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination.  The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.  The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015 with early adoption permitted.  The Company will adopt this standard update, as required, beginning with the first quarter of 2016, and does not expect it to have a material impact on its consolidated financial statements.  

Note 2. Acquisitions and Divestitures

Earthstone Energy Reverse Acquisition

On December 19, 2014, the Company and OVR closed the Exchange. In this transaction, OVR contributed to the Company the membership interests of its three wholly-owned subsidiaries, which included producing assets, undeveloped acreage and cash.  OVR received approximately 9.124 million shares of newly issued common stock, $0.001 par value per share (the “Common Stock”), of the Company. The Exchange resulted in a change of control of the Company. The Exchange has been accounted in accordance with FASB Accounting Standards Codification (“ASC”)805, Business Combinations (“ASC 805”) as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes although Earthstone is the acquirer for legal purposes. ASC 805 also requires, that among other things, assets acquired and liabilities assumed to be measured at their acquisition date fair values. The results of operations from Earthstone’s legacy assets are reflected in the Company’s consolidated statement of operations beginning December 19, 2014.

An allocation of the purchase price was prepared using, among other things, the 2014 year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to the December 19, 2014 acquisition date. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Earthstone tax return and certain accruals and includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.

9

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets (in thousands, except share and share price amounts):

Shares of Common Stock outstanding before the Exchange		1,734,988
Company director and officer restricted shares that vested    in the Exchange		18,400
Shares of Common Stock issued in the Exchange		9,124,452
Total shares of Common Stock outstanding following the    Exchange		10,877,840
Shares of Common Stock issued as consideration		1,753,388
Closing price of Common Stock (1)	$	19.08
Total purchase price	$	33,455
Estimated Fair Value of Liabilities Assumed:
Current liabilities	$	7,852
Long-term debt		7,000
Deferred tax liability (2)		2,880
Asset retirement obligation		2,227
Amount attributable to liabilities assumed		19,959
Total purchase price plus liabilities assumed	$	53,414
Estimated Fair Value of Assets Acquired:
Cash (3)	$	2,920
Other current assets		3,466
Proved oil and natural gas properties (4) (5)		21,813
Unproved oil and natural gas properties		5,524
Other non-current assets		745
Amount attributable to assets acquired	$	34,468
Goodwill (6)	$	18,946

(1) The share price used for the determination of the purchase price was $19.08, which was the closing price of the Common Stock on December 19, 2014.

(2) This amount represents the recorded book value versus tax value difference in oil and natural gas properties and other net assets as of the date of the Exchange on a tax effected basis of approximately 35%. The tax basis of the legacy Earthstone assets were not adjusted in the Exchange. As noted above, however, ASC 805 requires that the Company in a reverse acquisition record the legacy Earthstone net assets at fair value on the date of the Exchange; the fair value of the net assets was in excess of the tax basis and as such required the recognition of a deferred tax liability.

(3) The components of cash flow in the Exchange in which the legacy Earthstone assets were acquired were $7.1 million in notes payable and accrued interest that was paid in full in conjunction with the Exchange less the cash acquired of $2.9 million.

(4) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $51.62 per barrel of oil and $4.58 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.     

(5) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projections of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4 Fair Value Measurements, below.

(6) Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. The goodwill recognized will not be deductible for tax purposes.

2014 Eagle Ford Acquisition Properties

Also on December 19, 2014, immediately following the Exchange, Flatonia Energy, LLC (“Flatonia”), Parallel Resource Partners, LLC (“Parallel”), and Sabine, closed the transactions contemplated by the Contribution Agreement by and among the Company, OVR, Sabine, Oak Valley Operating, LLC, Parallel, and Flatonia, whereby Parallel contributed 28.57% of the oil and natural gas property interests held by Flatonia, a wholly owned subsidiary of Parallel, in consideration for approximately 2.96 million shares of Common Stock (the “Contribution”). The assets subject to the Contribution Agreement were oil and natural gas property interests in producing wells and acreage in the Eagle Ford trend of Texas (the “2014 Eagle Ford Acquisition Properties”). One of the subsidiaries included in the Exchange is the operator of the 2014 Eagle Ford Acquisition Properties. The only relationship that Flatonia or Parallel

10

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

had with this subsidiary or the Company prior to the transaction was that the subsidiary is the operator of the 2014 Eagle Ford Acquisition Properties. The Contribution was accounted for as a business combination in accordance ASC 805 which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date.

An allocation of the purchase price was prepared using, the 2014 year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to December 19, 2014. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Flatonia tax return and certain accruals and it includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. The Company’s final allocation of purchase price is dependent on the seller’s tax return since Earthstone received carryover basis on Flatonia’s assets and liabilities because the Contribution Agreement was not a taxable transaction under the United States Internal Revenue Code of 1986, as amended. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.

The following table summarizes the consideration paid to acquire the 2014 Eagle Ford Acquisition Properties and the estimated values of those net assets (in thousands, except share and share price amounts):

Shares of Common Stock issued as consideration in    the Contribution		2,957,288
Closing price of Common Stock (1)	$	19.08
Total purchase price	$	56,425
Estimated Fair Value of Liabilities Assumed:
Deferred tax liability (2)	$	4,046
Asset retirement obligation		173
Amount attributable to liabilities assumed		4,219
Total purchase price plus liabilities assumed	$	60,644
Estimated Fair Value of Assets Acquired:
Proved oil and natural gas properties (3) (4)	$	34,745
Unproved oil and natural gas properties		21,853
Amount attributable to assets acquired	$	56,598
Goodwill (5)	$	4,046

(1) The share price used for the determination of the purchase price was $19.08, which was the closing price of the Common Stock on December 19, 2014.

(2) This amount represents the recorded book value to tax difference in the oil and natural gas properties as of the date of the Contribution Agreement on a tax effected basis of approximately 34%. As noted above, the Company received the net assets at Flatonia’s carryover tax basis and as such requires the recognition of a deferred tax liability.

(3) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $56.36 per barrel of oil and $3.36 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.     

(4) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projecting of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4 Fair Value Measurements, below.

(5) Goodwill was determined to be the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. The goodwill recognized will not be deductible for tax purposes.

11

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following unaudited supplemental pro forma combined condensed results of operations present consolidated information as though the Exchange and Contribution had been completed as of January 1, 2014. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Exchange or Contribution or any estimated costs that will be incurred to integrate the legacy Earthstone net assets and the 2014 Eagle Ford Acquisition Properties. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts).

	Three months ended September 30,		Nine months ended September 30,
	2014		2014
	(Unaudited)
Revenue	$	22,691	$	65,652
Income before taxes	$	10,506	$	26,340
Net income available to Earthstone common    stockholders	$	6,832	$	17,256
Pro forma net income per common share:
Basic and diluted	$	0.49	$	1.25

For the three and nine months ended September 30, 2015, the Company recognized $2.0 million and $7.3 million, respectively, of oil, natural gas and natural gas liquids sales related to the legacy Earthstone assets and operating expenses including depletion of $2.5 million and $8.4 million, respectively. There were no material non-recurring transaction costs related to this acquisition incurred during the three and nine months ended September 30, 2015.

For the three and nine months ended September 30, 2015, the Company recognized $3.2 million and $9.8 million, respectively, of oil, natural gas and natural gas liquids related to the 2014 Eagle Ford Acquisition Properties and operating expenses including depletion of $2.5 million and $7.9 million, respectively. There were no material non-recurring transaction costs related to this acquisition incurred during the three and nine months ended September 30, 2015.

Other Acquisitions

In June 2015, the Company acquired a 50% operated interest in two gross Austin Chalk wells, which hold approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production, with current gross production of 44 barrels of oil equivalent per day (“BOEPD”) all of which was oil.  Also during June 2015, the Company acquired additional acreage in northern Karnes County, Texas, increasing its total leasehold position to approximately 400 gross acres.  The Company currently has a 33% working interest in the Karnes acreage.  These two positions are adjacent to one another and will provide for 17 gross Eagle Ford locations with expected development beginning in the fourth quarter of 2015.

The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands):

Purchase price	$	4,066
Estimated fair value of assets acquired:
Proved oil and natural gas properties	$	588
Unproved oil and natural gas properties		3,496
Total assets acquired	$	4,084
Estimated fair value of liabilities assumed:
Asset retirement obligations	$	13
Other liabilities		5
Total liabilities assumed	$	18
Consideration paid	$	4,066

12

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Pro forma financial information, assuming the acquisition occurred at the beginning of each period presented, has not been presented because the effect on the Company’s results for each of those periods is not material.  The results of the above acquisitions have been included in the Company’s consolidated financials since the date of each acquisition.

In June 2015, the Company acquired additional acreage and increased the Company’s working interest in wells in existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.1 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells.  The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that are in the drilling and completion phase.

In August 2015, the Company acquired a 33% working interest in approximately 1,650 gross acres, in Southern Gonzales County, Texas for $3.3 million. This acreage supports 16 additional gross Eagle Ford locations.  

Divestitures

In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million.  The Company recorded a gain of $1.7 million on the sale.  The effective date of the transaction was March 1, 2015.

Note 3. Derivative Financial Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815 Derivatives and Hedging (“ASC Topic 815”), to account for its derivative financial instruments. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The counterparties to the Company’s current derivative contracts are lenders in the Company’s credit agreement, which is described in Note 6 Long-Term Debt below. The Company did not post collateral under any of these contracts as they are secured under the Company’s credit agreement with the same counterparties.

The Company’s crude oil and natural gas derivative positions are swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain on derivative contracts” on the Condensed Consolidated Statements of Operations. All derivative contracts are recorded at their fair market value and are included in the Company’s Condensed Consolidated Balance Sheets as assets or liabilities.

With an individual derivative counterparty, the Company may have multiple hedge positions that expire at various points in the future and result in fair value asset and liability positions. At the end of each reporting period, those positions are offset to a single fair value asset or liability for each commodity per counter party, and the netted balance is reflected in the Company’s Consolidated Balance Sheets as an asset or a liability.

The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

The Company had the following open crude oil derivative contracts as of September 30, 2015:

Period	Instrument	Commodity	Volume in Bbls		Fixed Price
October 2015 - December 2015	Swap	Crude Oil		16,500	$	95.10
October 2015 - March 2016	Swap	Crude Oil		30,000	$	57.00
October 2015 - June 2016	Swap	Crude Oil		90,000	$	58.00
October 2015 - December 2016	Swap	Crude Oil		150,000	$	60.80

13

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table summarizes the location and fair value amounts of all derivative instruments in the Condensed Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Condensed Consolidated Balance Sheets (in thousands):

		September 30, 2015						December 31, 2014
Derivatives not designated as hedging contracts under ASC Topic 815	Balance Sheet Location	Gross Recognized Assets / Liabilities		Gross Amounts Offset		Net Recognized Assets / Liabilities		Gross Recognized Assets / Liabilities		Gross Amounts Offset		Net Recognized Assets / Liabilities
Commodity contracts	Current derivative assets	$	3,626	$	—	$	3,626	$	3,569	$	—	$	3,569
Commodity contracts	Noncurrent derivative assets	$	287	$	—	$	287	$	—	$	—	$	—

The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative instruments in the Company’s Condensed Consolidated Statements of Operations (in thousands):

		Three months ended September 30,				Nine months ended September 30,
Derivatives not designated as hedging contracts under ASC Topic 815	Statement of Operations Location	2015		2014		2015		2014
Unrealized gain on commodity    contracts	Net gain on derivative contracts	$	3,425	$	2,369	$	344	$	1,155
Realized gain (loss) on commodity    contracts	Net gain on derivative contracts	$	1,741	$	120	$	4,178	$	(969	)
		$	5,166	$	2,489	$	4,522	$	186

Note 4. Fair Value Measurements

FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.

The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:

Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the nine months ended September 30, 2015.

Fair Value on a Recurring Basis

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy.

14

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the consolidated financial statements.

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):

September 30, 2015	Level 1		Level 2		Level 3		Total
Financial assets
Current derivative assets	$	—	$	3,626	$	—	$	3,626
Noncurrent derivative assets		—		287		—		287
Total financial assets	$	—	$	3,913	$	—	$	3,913
December 31, 2014
Financial assets
Current derivative assets	$	—	$	3,569	$	—	$	3,569
Total financial assets	$	—	$	3,569	$	—	$	3,569

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.

Fair Value on a Nonrecurring Basis

Asset Impairment

Oil and natural gas properties are measured at fair value on a nonrecurring basis. An impairment charge reduces the carrying values of oil and natural gas properties’ to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and 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. The Company did not recognize any impairment write-downs with respect to its oil and natural gas properties during the nine months ended September 30, 2015 or 2014.

Business Combinations

The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption.   Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 2 Acquisitions.

Asset Retirement Obligations

The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. See Note 7 Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

15

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 5. Earnings (Loss) Per Common Share

Basic earnings (loss) per share is computed by dividing net income (loss) attributable to shares of Common Stock by the basic weighted-average shares of Common Stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents.

The following table is a reconciliation of net income and weighted-average shares of Common Stock outstanding for purposes of calculating basic and diluted income per share:

	Three months ended September 30,				Nine months ended September 30,
(In thousands, except share and per share amounts)	2015		2014		2015			2014
Net income (loss)	$	1,718	$	4,214	$	(144	)	$	8,484
Weighted average common shares outstanding:
Basic		13,835,128		9,124,452		13,835,128			9,124,452
Diluted		13,835,128		9,124,452		13,835,128			9,124,452
Net income (loss) per common share:
Basic	$	0.12	$	0.46	$	(0.01	)	$	0.93
Diluted	$	0.12	$	0.46	$	(0.01	)	$	0.93

Note 6. Long-Term Debt

On December 19, 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “ESTE Credit Facility”).  The OVR credit facility was refinanced under the ESTE Credit Facility and the legacy credit facility of the Company was paid in full and terminated.

The initial borrowing base of the ESTE Credit Facility was $80.0 million and is subject to redetermination during May and November of each year. At the option of the borrower, the amounts borrowed under the credit agreement bear annual interest rates at either (a) LIBOR plus the applicable utilization margin of 1.50% to 2.50% (1.704% at September 30, 2015) or (b) the base rate plus the applicable utilization margin of 0.50% to 1.50% (3.75% at September 30, 2015). Principal amounts outstanding under the ESTE Credit Facility are due and payable in full at maturity on December 19, 2018. All of the obligations under the credit agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Additional payments due under the credit agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment fee ranges from 0.375% to 0.50% per year, depending upon the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees.

As of September 30, 2015, the Company had $11.2 million of debt outstanding, bearing an interest rate of 1.704%, $0.3 million of letters of credit outstanding and $68.5 million of borrowing base available under its ESTE Credit Facility.

The ESTE Credit Facility contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period.  As of September 30, 2015, the Company was in compliance with these covenants.

Interest expense for the three months ended September 30, 2015 and 2014, includes amortization of deferred financing costs of $65,000 and $38,000, respectively.  Interest expense for the nine months ended September 30, 2015 and 2014, includes amortization of deferred financing costs of $195,000 and $113,000, respectively.  Approximately $1.0 million, net of amortization, associated with the Company’s credit facilities has been capitalized as of September 30, 2015 and December 31, 2014, and was being amortized over the terms of the credit agreements.

Note 7. 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. The accretion of the asset retirement obligation is included in “Lease operating expense” in the Condensed Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.

16

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table summarizes the Company’s asset retirement obligation transactions recorded during the nine months ended September 30, 2015, and in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (in thousands):

	2015
Asset retirement obligations at December 31, 2014	$	6,078
Liabilities incurred		104
Accretion expense		425
Property dispositions		(403	)
Liabilities settled		(65	)
Revision of estimates		24
Asset retirement obligations at September 30, 2015	$	6,163

Based on expected timing of settlement, $0.3 million of the asset retirement obligation is classified as current at September 30, 2015.

Note 8. Related Party Transactions

FASB ASC Topic 850, Related Party Disclosures (“ASC Topic 850”), requires that transactions with related parties that would make a difference in decision making be disclosed so that users of the financial statements can evaluate their significance. Pursuant to ASC Topic 850, OVR and all of its members, most notably Oak Valley Management, LLC (“OVM”) and certain other members (“Certain Other Members of OVR”) are considered related parties.  The following are significant related party transactions between the Company and members of OVM as well as between the Company and Certain Other Members of OVR as of September 30, 2015 and December 31, 2014, and for the three and nine months ended September 30, 2015 and 2014.

The Company employs members of OVM. For each of the three months ended September 30, 2015 and 2014, the Company made payments totaling $0.8 million to these members as compensation for services and reimbursement of expenses. For the nine months ended September 30, 2015 and 2014, the Company made payments totaling $3.0 million and $2.9 million, respectively, to these members as compensation for services and reimbursement of expenses.  The payments are included in “General and administrative expense” on the Condensed Consolidated Statements of Operations or have been charged out to oil and natural gas properties.

The Company has business relationships with Certain Other Members of OVR and with companies that employ Certain Other Members of OVR.  At September 30, 2015 and December 31, 2014, the Company has liabilities of $1.0 million and $2.3 million, respectively, owed to such members and companies.  These amounts are included in “Accounts payable” on the Condensed Consolidated Balance Sheets.

Note 9. Income Taxes

For the three months ended September 30, 2015, the Company recorded income tax expense of $0.8 million, and for the nine months ended September 30, 2015, the Company recorded a benefit of $0.1, million both of which were deferred. The Company’s effective tax rate for the three and nine months ended September 30, 2015 was 32.1% and 32.8%, respectively, which is approximately 2% lower than the U.S. Federal statutory corporate income tax rate of 34% due to certain permanent differences.  The effective tax rate also includes approximately 0.9% of the estimated portion of the Company’s income that is subject to income tax in the states in which the Company operates. The Company did not record any tax provision for income tax in the three or nine months ended September 30, 2014 because OVR is a partnership and is not subject to taxation. As explained in Note 1 Basis of Presentation, all historical financial information prior to December 19, 2014 contained in this report is that of OVR and its subsidiaries.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with FASB ASC Topic 740, Income Taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax asset will be realized. The ultimate realization of deferred income tax assets, if any, is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.

17

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 10. Commitments and Contingencies

In the course of its business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state, and local environmental, health and safety laws and regulations and third party litigation.

Commitments

In 2014, the Company entered into an 18 month drilling contract to utilize a new-build drilling rig in its drilling operations.  The new rig is an upgrade and replacement of a rig with a drilling contract that was expiring.  The contract provides for a daily drilling rate of approximately $29,000.  In April 2015, the Company took delivery of the rig and commenced drilling.  As of September 30, 2015, the minimum commitment per the terms of the agreement is approximately $10.9 million. Further, in the event the Company breaks the contract and surrenders the rig, the contract provides for lump sum liquidated damages equal to approximately $20,000 per day through the end of the contract term. As of September 30, 2015 the liquidated damages amount is approximately $7.5 million.  

As a part of the 2013 Eagle Ford Acquisition, the Company and its primary working interest partner in the area ratified several long-term natural gas purchasing and natural gas processing contracts. As is customary in the industry, the Company has reserved gathering and processing capacity in a pipeline. In one of the contracts, the Company and its primary working interest partner have a volume commitment, whereby the owner of the pipeline is paid a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity. Since the time of the acquisition, the volume commitment has not been met. The rate and terms under this purchasing and processing contract expire on June 1, 2021.  As of September 30, 2015, the Company’s share of the remaining commitment on this contract is approximately $4.7 million.

Contingencies

Environmental

The Company’s operations are subject to risks normally associated with the exploration for and the production of oil and natural gas, including blowouts, fires, and environmental risks such as oil spills or natural gas leaks that could expose the Company to liabilities associated with these risks.

In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks.

However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above.

Legal

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. In July 2015, EF Non-Op, LLC, a subsidiary of the Company, filed suit in the 125^th Judicial District Court of Harris County, Texas against the operator of its properties in LaSalle County, Texas. In the case EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP) the Company claims the operator has breached the applicable joint operating agreements in numerous ways, including improper authorization for expenditure requests, improper and imprudent operations, misrepresentation of charges and excessive billings, as well as refusal to provide requested information. The Company also claims damages from negligent representation and fraud.  The Company is seeking all relief to which it is entitled, including consequential damages and attorney’s fees. The outcome of this proceeding is uncertain, and while the Company is confident in its position, any potential monetary recovery to the Company cannot be estimated at this time.

18

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of our financial condition, results of operations, liquidity and capital resources should be read together with our unaudited condensed consolidated financial statements and notes to unaudited condensed consolidated financial statements contained in this report as well as our Annual Report on Form 10-K for the year ended December 31, 2014. Unless the context otherwise requires, the terms “the Company,” “our,” “we,” “us,” and “Earthstone” refer to Earthstone Energy, Inc. and its consolidated subsidiaries.

Statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties, including those discussed below, which cause actual results to differ from those expressed.  For more information, see “Cautionary Statement Concerning Forward-Looking Statements.”

Overview

We are an independent oil and gas company engaged in the acquisition, development, exploration and production of onshore oil and natural gas reserves.  As further discussed in this report, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to acquire, discover and develop commercial quantities of oil and natural gas reserves that can be produced at a profit, and assemble an oil and natural gas reserve base with a market value exceeding its acquisition, development and production costs.

On December 19, 2014, we acquired three operating subsidiaries of Oak Valley Resources, LLC, a privately-held Delaware limited liability company (“OVR”), in exchange for shares of our common stock (the “Exchange”), which resulted in a change of control. Pursuant to the Exchange, OVR contributed to us the membership interests of its three subsidiaries, Oak Valley Operating, LLC (“OVO”), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”), in exchange for approximately 9.124 million shares, representing 84% of our common stock.  The Exchange has been accounted for as a reverse acquisition in which Oak Valley is considered the acquirer for accounting purposes.  All historical financial information prior to December 19, 2014, contained in this report is that of Oak Valley.

Immediately following the Exchange, we acquired an additional 20% undivided ownership interest in certain oil and natural gas properties located in Fayette and Gonzales Counties, Texas, (the “2014 Eagle Ford Acquisition Properties”) in exchange for the issuance of approximately 2.957 million shares of our common stock (the “Contribution Agreement”) to Flatonia Energy, LLC (“Flatonia”), increasing our ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest.  As a result of the share issuance to Flatonia, OVR’s ownership in the Company decreased from 84% to 66%.

In April 2015, we sold our Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million, recording a gain of $1.7 million.  The effective date of the transaction was March 1, 2015.

In June 2015, we acquired a 50% operated interest in two gross Austin Chalk wells which hold approximately 1,000 gross acres in southern Gonzales county, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production, with gross production of 44 barrels of oil equivalent per day (“BOEPD”) all of which was oil. Also in June, we acquired additional acreage in northern Karnes County, Texas, increasing our total leasehold position to approximately 400 gross acres.  We currently have a 33% working interest in the Karnes acreage.  These two positions are adjacent to one another and will provide 17 gross Eagle Ford locations.  We expect to begin development of this area in the fourth quarter of 2015.

In June 2015, we acquired additional acreage and increased our working interest in wells in existing Bakken units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.1 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells.  The acquisition included 164 net acres which allowed us to increase our working interest in approximately 41 producing wells and 21 wells that in the drilling and completion phase.

In August 2015, we acquired a 33% working interest in approximately 1,650 gross acres, in Southern Gonzales County, Texas for $3.3 million. This acreage supports 16 additional gross Eagle Ford locations.  

19

Results of Operations

Three months ended September 30, 2015, compared to the three months ended September 30, 2014

Sales and Other Operating Revenues

The quantities of oil, natural gas, and natural gas liquids produced and sold, the average sales price per unit sold and our related revenues, exclusive of settlements related to derivative contracts for the three months ended September 30, 2015 and 2014, are presented below:

	Three months ended September 30,
	2015		2014		Change
Sales volumes:
Oil (MBbl)		246		95		151
Natural gas (MMcf)		742		521		221
Natural gas liquids (MBbl)		58		32		26
Barrels of oil equivalent (MBOE) (1)		428		214		214
Barrels of oil equivalent per day (BOEPD) (1)		4,646		2,327		2,319
Average prices realized: (2)
Oil (Bbl)	$	42.20	$	93.69	$	(51.49	)
Natural gas (Mcf)	$	2.66	$	4.05	$	(1.39	)
Natural gas liquids (Bbl)	$	11.73	$	28.94	$	(17.21	)

	Three months ended September 30,
(In thousands)	2015			2014		Change
Oil, natural gas, and natural gas liquids revenues:
Oil	$	10,385		$	8,916	$	1,469
Natural gas		1,971			2,113		(142	)
Natural gas liquids		677			928		(251	)
Other operating revenues:
Gathering income		60			98		(38	)
Loss on sales of oil and gas properties, net		(13	)		—		(13	)
Total revenues	$	13,080		$	12,055	$	1,025

(1) Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equals one barrel of oil equivalent (BOE). This ratio does not assume price equivalency and, given price differentials, the price per barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2) Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting. Our derivatives for 2015 and 2014 have been marked-to-market through our statement of operations as other income/expense: which means that all our realized gains/losses on these derivatives are reported in other income/expense. For further information see the Net Gain on Derivative Contracts discussed below.  

Sales of Oil

For the three months ended September 30, 2015, oil revenues increased by $1.5 million or 16% relative to the comparable period in 2014. Of the increase, $14.2 million was attributable to increased volume, which was offset by $12.7 million attributable to a decrease in our realized price. The volume of oil produced and sold increased by 151 MBbls; 93 MBbls were provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 55 MBbls of the total increase were provided by the legacy Earthstone assets. The remaining difference in oil volumes resulted from additional production on new wells in our non-operated Eagle Ford property which were partially offset by normal production declines on our other properties.  Our average realized price per Bbl decreased from $93.69 for the three months ended September 30, 2014 to $42.20 or 55% for the three months ended September 30, 2015.

Sales of Natural Gas

For the three months ended September 30, 2015, natural gas revenues decreased by $0.1 million or 7% relative to the comparable period in 2014. Of the decrease $1.0 million was attributable to the decline in our realized price which was offset by $0.9 million attributable to increased volume. Our average realized price per Mcf decreased from $4.05 for the three months ended September 30,

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2014 to $2.66or 34% for the three months ended September 30, 2015. The volume of natural gas produced and sold increased by 221 MMcf; 23 MMcf was provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 68 MMcf of the total was provided by the legacy Earthstone assets. Also contributing to the increase was 202 MMcf provided by our non-operated Eagle Ford property due to new wells which was partially offset by the loss of 49 MMcf from our Louisiana properties that were sold effective March 1, 2015. The remaining 23 MMcf decrease was due to production declines and variability in sales volumes in our conventional properties in Oklahoma and East Texas.

Sales of Natural Gas Liquids

For the three months ended September 30, 2015, natural gas liquids revenues decreased by $0.3 million or 27% relative to the comparable period in 2014. Of the decrease, $1.0 million was attributable to a decrease in our realized price which was offset by a $0.7 million increase due to volume. The average realized price per Bbl decreased from $28.94 for the three months ended September 30, 2014 to $11.73 or 59% for the three months ended September 30, 2015. The volume of natural gas liquids sales produced and sold increased by 26 MBbls; 8 MBbls were provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement. New wells on our non-operated Eagle Ford property provided 12 MBbls of the total increase; 6 MBbls of the total were provided by the legacy Earthstone assets.

Production Costs

Our production costs for the three months ended September 30, 2015 and 2014 are summarized in the table below:

	Three months ended September 30,
(In thousands)	2015			2014			Change
Lease operating expenses	$	4,138		$	2,536		$	1,602
Severance taxes	$	746		$	481		$	265
Re-engineering and workover expenses	$	234		$	234		$	—
LOE per BOE*	$	9.18		$	10.95		$	(1.77	)
Severance tax as a percent of oil, natural gas and natural gas liquids revenues		5.72	%		4.02	%		1.70	%

* Excludes ad valorem tax and accretion expense related to our asset retirement obligations.

Lease Operating Expenses

Lease operating expenses (“LOE”) includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements.

	Three months ended September 30,
(In thousands)	2015		2014		Change
Production related LOE	$	3,924	$	2,344	$	1,580
Ad valorem taxes		71	$	114		(43	)
Accretion expense		143	$	78		65
Total LOE	$	4,138	$	2,536	$	1,602

Total LOE increased by $1.6 million or 63% for the three months ended September 30, 2015 relative to the comparable period in 2014, which was due to the addition of the legacy Earthstone assets, costs on the new wells that we drilled and completed after the third quarter of 2014 as well as having a larger share of the gross costs in our operated Eagle Ford property due to the additional interests we acquired in late 2014 pursuant to the Contribution Agreement. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, decreased by 16% or $1.77 per BOE from $10.95 in 2014 to $9.18 in 2015. The decrease on a per BOE basis was due to a decrease in the cost of oil field services as well as economies of scale on our operated Eagle Ford property which offset the increase that resulted from the addition of the legacy Earthstone assets which have a higher operating cost on a per BOE basis than many of our Eagle Ford wells.

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Severance Taxes

Severance taxes increased by $0.3 million or 55% for the three months ended September 30, 2015 relative to the comparable period in 2014, primarily due to the additional production from new wells drilled and completed after the third quarter of 2014 on our operated Eagle Ford property as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement in that same property and the addition of the legacy Earthstone assets. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes increased from 4.02% to 5.72%, primarily due to a shift in our sales; for the three month period ended September 30, 2015, approximately 80% of our oil, natural gas and natural gas liquids revenue came from oil versus approximately 75% in same period during 2014. These oil revenues are taxed at the full rate whereas a large portion of our natural gas and natural gas liquids sales qualify for partial or full severance tax exemptions.  Additionally, as result of the Exchange completed in late 2014, we added significant oil production from legacy Earthstone assets located in North Dakota and Montana; these states have higher severance tax rates than Texas where our operated Eagle Ford wells are located.    

Re-engineering and Workovers

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations which include major surface repairs. These costs remained consistent for the three months ended September 30, 2015 relative to the comparable period in 2014, of which were both $0.2 million, due to the mix of projects and the variability of our working interest in the areas in which the projects are occurring. We continually evaluate these projects and weigh the advantages of the projects while seeking to control current and future expenditures.

General and Administrative Expenses

General and administrative expenses (“G&A”), primarily consist of employee remuneration, professional and consulting fees and other overhead expenses.  G&A expenses increased by $0.9 million from $1.6 million to $2.5 million for the three months ended September 30, 2015 relative to the comparable period in 2014, which was due to increased personnel costs and reporting requirements resulting from the Exchange completed in late 2014.  

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) increased during the three months ended September 30, 2015 by $2.8 million, or 54% compared to the same period in 2014, due to increased production. Despite significant additional capital costs from both acquisitions and the execution of our drilling program, on a per BOE basis DD&A decreased by 23% or $5.64 from $24.61 to $18.97 due to the proportionately greater addition of oil and gas reserves.    

Interest Expense

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense was comparable from quarter to quarter and was $0.2 million for the three months ended September 30, 2015 and 2014.

Net Gain on Derivative Contracts

During the three months ended September 30, 2015, we recorded a net gain on derivative contracts of $5.2 million, consisting of net realized gains on settlements of $1.7 million and unrealized mark-to-market gains of $3.5 million. During the three months ended September 30, 2015, all of our net realized settlements related to crude oil contracts. During the three months ended September 30, 2014, we recorded a net gain on derivative contracts of $2.5 million, consisting of net realized gains on settlements of $0.1 million and unrealized mark-to-market gains of $2.4 million.

Income Tax Expense

During the three months ended September 30, 2015 we recorded an income tax expense of $0.8 million as a result of our pre-tax net income. Our effective tax rate for the quarter was approximately 32% which is consistent with our expected annual tax rate. The annual effective tax rate is less than the US Federal statutory tax rate due to permanent differences between book and tax income; primarily the non-deductible portion of general and administrative costs. During the three months ended September 30, 2014 we did not record any provision for income tax since OVR is a partnership and for federal income tax purposes is not subject to federal income taxes or state or local income taxes that follow federal treatment. As a result of the Exchange, all historical financial information prior to December 19, 2014 contained in this report is that of OVR and its subsidiaries.

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Nine months ended September 30, 2015, compared to the nine months ended September 30, 2014

Sales and Other Operating Revenues

The quantities of oil, natural gas, and natural gas liquids produced and sold, the average sales price per unit sold and our related revenues, exclusive of settlements related to derivative contracts for the nine months ended September 30, 2015 and 2014, are presented below:

	Nine months ended September 30,
	2015		2014		Change
Sales volumes:
Oil (MBbl)		684		262		422
Natural gas (MMcf)		2,039		1,644		395
Natural gas liquids (MBbl)		161		92		69
Barrels of oil equivalent (MBOE) (1)		1,185		628		557
Barrels of oil equivalent per day (BOEPD) (1)		4,340		2,300		2,040
Average prices realized: (2)
Oil (Bbl)	$	46.18	$	96.65	$	(50.47	)
Natural gas (Mcf)	$	2.69	$	4.54	$	(1.85	)
Natural gas liquids (Bbl)	$	13.43	$	30.82	$	(17.39	)

	Nine months ended September 30,
(In thousands)	2015		2014		Change
Oil, natural gas, and natural gas liquids revenues:
Oil	$	31,586	$	25,292	$	6,294
Natural gas		5,483		7,459		(1,976	)
Natural gas liquids		2,164		2,842		(678	)
Other operating revenues:
Gathering income		233		293		(60	)
Gain on sales of oil and gas properties, net		1,667		—		1,667
Total revenues	$	41,133	$	35,886	$	5,247

(1) Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equals one barrel of oil equivalent (BOE). This ratio does not assume price equivalency and, given price differentials, the price per barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2) Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting. Our derivatives for 2015 and 2014 have been marked-to-market through our statement of operations as other income/expense, which means that all our realized gains/losses on these derivatives are reported in other income/expense. For further information see the Net Gain on Derivative Contracts discussed below.  

Sales of Oil

For the nine months ended September 30, 2015, oil revenues increased by $6.3 million or 25% relative to the comparable period in 2014. Of the increase, $40.8 million was attributable to increased volume, which was offset by $34.5 million attributable to a decrease in our realized price. The volume of oil we produced and sold increased by 422 MBbls; 273 MBbls were provided by our operated Eagle Ford property as a result of additional production from new wells drilled and completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 162 MBbls of the total increase were provided by the legacy Earthstone assets. These significant increases were partially offset by production declines and variability in sales volumes in our conventional properties Texas. Our average realized price per Bbl decreased from $96.65 for the nine months ended September 30, 2014 to $46.18 or 52% for the nine months ended September 30, 2015.

Sales of Natural Gas

For the nine months ended September 30, 2015, natural gas revenues decreased by $2.0 million or 26% relative to the comparable period in 2014. Of the decrease $3.8 million was attributable to the decrease in our realized price which was offset by $1.8 million attributable to increased volume. Our average realized price per Mfc decreased from $4.54 for the nine months ended September 30, 2014 to $2.69 or 41% for the nine months ended September 30, 2015. The volume of natural gas produced and sold increased by 395 MMcf; 84 MMcf was provided by our operated Eagle Ford property as a result of additional production from new wells drilled and

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completed after the third quarter of 2014 as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement;206 MMcf of the total increase was provided by the legacy Earthstone assets. Also contributing to the increase, was 339 MMcf provided by our non-operated Eagle Ford property due to new wells which was partially offset by the loss of 125 MMcf from the Louisiana properties that were soldin April 2015. The remaining 109 MMcf decrease in volumes was due to decreased production in our conventional properties located in Oklahoma and East Texas.

Sales of Natural Gas Liquids

For the nine months ended September 30, 2015, natural gas liquids revenues decreased by $0.7 million or 24% relative to the comparable period in 2014. Of the decrease, $2.8 million was attributable to a decrease in our realized price which was offset by a $2.1 million increase due to volume. The average realized price per Bbl decreased from $30.82 for the nine months ended September 30, 2014 to $13.43 or 56% for the nine months ended September 30, 2015. The volume of natural gas liquids sales produced and sold increased by 69 MBbls; 26 MBbls of the total were provided by our operated Eagle Ford property as a result of additional production from new wells as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement; 22 MBbls of the total were provided by the legacy Earthstone assets and 21 MBbls came from new wells drilled during 2014 and 2015 in our non-operated Eagle Ford property.

Production Costs

Our production costs for the nine months ended September 30, 2015 and 2014 are summarized in the table below:

	Nine months ended September 30,
(In thousands)	2015			2014			Change
Lease operating expenses	$	12,751		$	7,210		$	5,541
Severance taxes	$	2,122		$	1,479		$	643
Re-engineering and workover expenses	$	520		$	553		$	(33	)
LOE per BOE*	$	10.16		$	10.53		$	(0.37	)
Severance tax as a percent of oil, natural gas and natural gas liquids revenues		5.41	%		4.16	%		1.25	%

* Excludes ad valorem tax and accretion expense related to our asset retirement obligations.

Lease Operating Expenses

Lease operating expenses (“LOE”) includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements.  

	Nine months ended September 30,
(In thousands)	2015		2014		Change
Production related LOE	$	12,033	$	6,614	$	5,419
Ad valorem taxes		293		367		(74	)
Accretion expense		425		229		196
Total LOE	$	12,751	$	7,210	$	5,541

Total LOE increased by $5.5 million or 77% for the nine months ended September 30, 2015 relative to the comparable period in 2014, which was due to the addition of the legacy Earthstone assets, costs on the new wells that we drilling and completed after the third quarter of 2014 in our operated Eagle Ford property as well as having a larger share of the gross costs in our Eagle Ford property due to the additional interests we acquired in late 2014 pursuant to the Contribution Agreement. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, decreased by 4% or $0.37 per BOE from $10.53 in 2014 to $10.16 in 2015. The decrease on a per BOE basis was due to a decrease in the cost of oil field services as well as economies of scale on our operated Eagle Ford property which offset the increase that resulted from the addition of the legacy Earthstone assets which have a higher operating cost on a per BOE basis than many of our Eagle Ford wells.

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Severance Taxes

Severance taxes increased by $0.6 million or 43% for the nine months ended September 30, 2015 relative to the comparable period in 2014, primarily due to the additional production from new wells drilled and completed after the third quarter of 2014 in our operated Eagle Ford property as well as the additional interests we acquired in late 2014 pursuant to the Contribution Agreement in that same property and the addition of the legacy Earthstone assets. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes increased from 4.16% to 5.41%, primarily due to a shift in our sales; for the nine month period ended September 30, 2015, approximately 81% of our oil, natural gas and natural gas liquids revenue came from oil versus approximately 71% in same period during 2014. These oil revenues are taxed at the full rate whereas a large portion of our natural gas and natural gas liquids sales qualify for partial or full severance tax exemptions.  Additionally, in late 2014, as result of the Exchange we added significant oil production from legacy Earthstone assets located in North Dakota and Montana; these states have higher severance tax rates than Texas where our operated Eagle Ford wells are located.

Re-engineering and Workovers

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations which include major surface repairs. These costs decreased slightly for the nine months ended September 30, 2015 relative to the comparable period in 2014 since prior expenses reduced the need for these types of repairs in the current period. We continually evaluate these projects and weigh the advantages of the projects while seeking to control current and future expenditures.  

General and Administrative Expenses

General and administrative expenses (“G&A”), primarily consist of employee remuneration, professional and consulting fees and other overhead expenses.  G&A expenses increased by $2.7 million from $4.8 million to $7.5 million for the nine months ended September 30, 2015 relative to the comparable period in 2014, which was due to increased personnel costs and reporting requirements resulting from the Exchange completed in late 2014.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) increased during the nine months ended September 30, 2015 by $9.7 million, or 74% compared to the same period in 2014. Despite significant additional capital costs from both the acquisitions and the execution of our drilling program, on a per BOE basis depletion, depreciation and amortization remained decreased by 8% or $1.59 from $20.75 to $19.16 due to the proportionately greater addition of oil and gas reserves.    

Interest Expense

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense was comparable period over period and was $0.5 million for the nine months ended September 30, 2015 and 2014.

Net Gain on Derivative Contracts

During the nine months ended September 30, 2015, we recorded a net gain on derivative contracts of $4.5 million, consisting of net realized gains on settlements of $4.2 million and unrealized mark-to-market gains of $0.3 million. During the nine months ended September 30, 2015 our net realized settlements consisted of a $4.0 million gain related to crude oil contracts and a $0.2 million gain related to natural gas contracts. During the nine months ended September 30, 2014, we recorded a net gain on derivative contracts of $0.2 million, consisting of net realized losses on settlements of $1.0 million and unrealized mark-to-market gains of $1.2 million.

Income Tax Expense

During the nine months ended September 30, 2015 we recorded an income tax benefit of $0.1 million as a result of our pre-tax net loss. Our effective tax rate for the nine months was approximately 33% which was less than the US Federal statutory tax rate due to permanent differences between book and tax income; primarily the non-deductible portion of general and administrative costs. During the nine months ended September 30, 2014 we did not record any provision for income tax since OVR is a partnership and for federal income tax purposes is not subject to federal income taxes or state or local income taxes that follow federal treatment. As a result of the Exchange, all historical financial information prior to December 19, 2014 contained in this report is that of OVR and its subsidiaries.

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Liquidity and Capital Resources

We expect to finance future acquisition, development and exploration activities through cash flows from operating activities, borrowings under our credit facility, the sale of non-strategic assets, various means of corporate and project financing, and the issuance of additional debt and/or equity securities. In addition, we may continue to partially finance our drilling activities through the sale of participations to industry partners or financial institutions, and we could structure such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs.

Senior Secured Revolving Credit Facility

In December 2014, we entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “Credit Agreement”) with BOKF, NA dba Bank of Texas (“Bank of Texas”), as agent and lead arranger, Wells Fargo Bank, National Association (“Wells Fargo”), as syndication agent, and the Lenders signatory thereto (collectively with Bank of Texas and Wells Fargo, the “Lender”).

The initial borrowing base of the Credit Agreement was $80.0 million and is subject to redetermination during May and November of each year. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus the applicable utilization margin of 1.50% to 2.50% or (b) the base rate of 3.25% per year plus the applicable utilization margin of 0.50% to 1.50%. Principal amounts outstanding under the Credit Agreement are due and payable in full at maturity on December 19, 2018. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of our assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate ranges from 0.375% to 0.50% per year, depending upon the unutilized portion of the borrowing base in effect from time to time. We are also required to pay customary letter of credit fees.  At September 30, 2015, we had approximately $68.5 million of borrowing capacity under our Credit Agreement.  Our Credit Agreement contains customary covenants and we were in compliance with them as of September 30, 2015.

Cash Flows from Operating Activities

Substantially all of our cash flows from or used in operating activities are derived from and used in the production of our oil, natural gas, and natural gas liquids reserves.  We use any excess cash flows to fund our on-going exploration and development activities in search of new reserves. Variations in cash flows from operating activities may impact our level of exploration and development expenditures.

Cash flows provided by operating activities for the nine months ended September 30, 2015 were $4.3 million compared to $61.9 million for the nine months ended September 30, 2014.  The decrease was due to changes in our working capital items. Accounts payable and accrued expenses decreased during the nine month period ended September 30, 2015 by $15.5 million; this reduction used a significant portion of the operating cash flows we generated but positively impacted our working capital and overall balance sheet.  We believe that we have sufficient liquidity and capital resources to execute our business plan over the next 12 months and for the foreseeable future.

Cash Flows from Investing Activities

Cash applied to oil and natural gas properties for the nine months ended September 30, 2015 and 2014 was $57.7 million and $54.5 million, respectively. Cash applied to other non-oil and gas property fixed assets for the nine months ended September 30, 2015 and 2014, was $0.3 million and $0.6 million, respectively. We also used $8.7 of cash to acquire acreage and producing assets in both the Eagle Ford trend of Texas and the Bakken trend in North Dakota. The sale of our Louisiana assets provided $3.4 million of cash in the second quarter of 2015.

Derivative Instrument and Hedging Activity

We do not engage in speculative commodity trading activities and do not hedge all available or anticipated quantities of our production. In implementing our hedging strategy, we seek to effectively manage cash flow to minimize price volatility.

We seek to reduce our sensitivity to oil and natural gas price volatility and secure favorable debt financing terms by entering into commodity derivative transactions.  We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations.  

Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur.  Our open commodity derivative instruments were in a net asset position with a fair value of $3.9 million.  Based on the September 30, 2015 published commodity futures price curves for the underlying commodity, a 10% increase in per unit commodity prices would cause

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the total fair value asset of our commodity derivative financial instruments to decrease by approximately $1.3 million to a net asset of $2.6 million. A 10% decrease in per unit commodity prices would cause the total fair value net asset of our commodity derivative financial instruments to increase by approximately $1.1 million to $5.0 million. There would also be a similar increase or decrease in “Net gain on derivative contracts” in the Consolidated Statements of Operations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements in this report, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Recently Issued Accounting Standards

Revenue Recognition - In May 2014, the Federal Accounting Standards Board (“FASB”) issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. We will adopt this standards update, as required, beginning with the first quarter of 2018. We are in the process of evaluating the impact, if any, of this guidance on our consolidated financial statements.

Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in financial statements.  Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset.  Amortization of the costs is reported as interest expense.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  We will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods.  We do not expect the adoption of this new presentation guidance to have a material impact on our consolidated balance sheets.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination.  The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.  The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted.  We will adopt this standard update, as required, beginning with the first quarter of 2016, and do not expect it to have a material impact on our consolidated financial statements.  

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this Item.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.

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We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2015. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Accounting Officer. Based on this evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that, as of September 30, 2015, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we may be involved in various legal proceedings and claims in the ordinary course of business. As of September 30, 2015, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.  

See Note 10 Commitments and Contingencies in the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this report, which is incorporated herein by reference, for material matters that have arisen since the filing of our Annual Report on Form 10-K for the year ended December 31, 2014.

Item 1A. Risk Factors

There have been no material changes during the period ended September 30, 2015 in our “Risk Factors” as discussed in Item 1A to our Annual Report on Form 10-K for the year ended December 31, 2014.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 6. Exhibits

Exhibit			Incorporated by Reference		Filing	Filed	Furnished
No.	Description	Form	SEC File No.	Exhibit	Date	Herewith	Herewith
31.1	Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act					X
31.2	Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act					X
32.1	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act						X
32.2	Certification of the Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act						X
101.INS	XBRL Instance Document					X
101.SCH	XBRL Schema Document					X
101.CAL	XBRL Calculation Linkbase Document					X
101.DEF	XBRL Definition Linkbase Document					X
101.LAB	XBRL Label Linkbase Document					X
101.PRE	XBRL Presentation Linkbase Document					X

29

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	EARTHSTONE ENERGY, INC.
	By:	/s/ Frank A. Lodzinski
	Name:	Frank A. Lodzinski
Date: November 12, 2015	Title:	President and Chief Executive Officer (Principal Executive Officer)

	By:	/s/ G. Bret Wonson
	Name:	G. Bret Wonson
Date: November 12, 2015	Title:	Principal Accounting Officer (Principal Financial Officer)

30

EX-31.1

Exhibit 31.1

Certification

I, Frank A. Lodzinski, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Earthstone Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 12, 2015	/s/ Frank A. Lodzinski
	Frank A. Lodzinski
	Principal Executive Officer

EX-31.2

Exhibit 31.2

Certification

I, G. Bret Wonson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Earthstone Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 12, 2015	/s/ G. Bret Wonson
	G. Bret Wonson
	Principal Financial Officer

EX-32.1

Exhibit 32.1

Section 1350 Certification

I, Frank A. Lodzinski, certify that:

In connection with the Quarterly Report on Form 10-Q of Earthstone Energy, Inc. (the “Company”) for the period ended September 30, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Frank A. Lodzinski, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 12, 2015	/s/ Frank A. Lodzinski
	Frank A. Lodzinski
	President and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Section 1350 Certification

I, G. Bret Wonson, certify that:

In connection with the Quarterly Report on Form 10-Q of Earthstone Energy, Inc. (the “Company”) for the period ended September 30, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, G. Bret Wonson, Chief Accounting Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 12, 2015	/s/ G. Bret Wonson
	G. Bret Wonson
	Chief Accounting Officer

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Long-Term Debt - Additional Information (Details) - USD ($)		3 Months Ended		9 Months Ended
	Dec. 19, 2014	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Jun. 30, 2015	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt		$ 11,191,000		$ 11,191,000				$ 11,191,000
Amortization of deferred financing costs		65,000	$ 38,000	195,000	$ 195,000	$ 113,000	$ 113,000
Deferred financing cost, net of amortization		1,000,000		1,000,000					$ 1,000,000
Four Year Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Line of credit, maturity period	4 years
Initial borrowing of the credit facility		80,000,000		$ 80,000,000
Debt outstanding maturity				Dec. 19, 2018
Long-term debt		$ 11,200,000		$ 11,200,000
Long-term debt, percentage bearing interest rate		1.704%		1.704%
Letters of credit outstanding amount		$ 300,000		$ 300,000
Borrowing base available under credit facility		$ 68,500,000		$ 68,500,000
Line of credit facility, covenant terms				The ESTE Credit Facility contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period.
Four Year Senior Secured Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Commitment fee percentage				0.375%
Four Year Senior Secured Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Commitment fee percentage				0.50%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member]
Debt Instrument [Line Items]
Effective interest rate		1.704%		1.704%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage				1.50%
Four Year Senior Secured Revolving Credit Facility [Member] | LIBOR Adjusted Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage				2.50%
Four Year Senior Secured Revolving Credit Facility [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Effective interest rate		3.75%		3.75%
Four Year Senior Secured Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin percentage				0.50%
Four Year Senior Secured Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin percentage				1.50%

XML

Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Parenthetical) (Details) $ / shares in Units, $ in Thousands		3 Months Ended
	Dec. 19, 2014 USD ($) $ / shares $ / bbl $ / Mcf	Sep. 30, 2015
Business Acquisition [Line Items]
Exchange tax rate		34.00%
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Closing price of Common Stock | $ / shares	$ 19.08
Exchange tax rate	35.00%
Business combination assets acquired notes payable and accrued interest | $	$ 7,100
Cash | $	$ 2,920
Weighted average commodity prices of oil | $ / bbl	51.62
Weighted average commodity prices of natural gas	4.58
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Closing price of Common Stock | $ / shares	$ 19.08
Exchange tax rate	34.00%
Weighted average commodity prices of oil | $ / bbl	56.36
Weighted average commodity prices of natural gas	3.36

XML

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ 811	$ (69)
Effective tax rate	32.10%	32.80%
Difference between effective tax rate and U.S. federal statutory corporate income tax rate	2.00%
U.S. Federal statutory corporate income tax rate	34.00%
States income tax rate	0.90%

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 4. Fair Value Measurements

FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.

The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:

Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the nine months ended September 30, 2015.

Fair Value on a Recurring Basis

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy.

The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the consolidated financial statements.

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):

September 30, 2015	Level 1		Level 2		Level 3		Total
Financial assets
Current derivative assets	$	—	$	3,626	$	—	$	3,626
Noncurrent derivative assets		—		287		—		287
Total financial assets	$	—	$	3,913	$	—	$	3,913
December 31, 2014
Financial assets
Current derivative assets	$	—	$	3,569	$	—	$	3,569
Total financial assets	$	—	$	3,569	$	—	$	3,569

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.

Fair Value on a Nonrecurring Basis

Asset Impairment

Oil and natural gas properties are measured at fair value on a nonrecurring basis. An impairment charge reduces the carrying values of oil and natural gas properties’ to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and 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. The Company did not recognize any impairment write-downs with respect to its oil and natural gas properties during the nine months ended September 30, 2015 or 2014.

Business Combinations

The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption.   Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 2 Acquisitions.

Asset Retirement Obligations

The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. See Note 7 Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

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Derivative Financial Instruments - Summary of Gross and Net Information About Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments Gain Loss [Line Items]
Unrealized gain on commodity contracts			$ 344	$ 1,155
Net gain (loss) on derivative contracts	$ 5,166	$ 2,489	4,522	186
Derivatives Not Designated as Hedging Contracts [Member] | Net Gain (Loss) On Derivative Contracts [Member]
Derivative Instruments Gain Loss [Line Items]
Unrealized gain on commodity contracts	3,425	2,369	344	1,155
Realized gain (loss) on commodity contracts	$ 1,741	$ 120	$ 4,178	$ (969)

XML

Derivative Financial Instruments - Schedule of Location and Fair Value Amounts of All Derivative Instruments (Details) - Derivatives Not Designated as Hedging Contracts [Member] - Commodity Contracts [Member] - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current Derivative Assets [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Assets	$ 3,626	$ 3,569
Net Recognized Assets	3,626	$ 3,569
Noncurrent Derivative Assets [Member]
Derivatives Fair Value [Line Items]
Gross Recognized Assets	287
Net Recognized Assets	$ 287

XML

Fair Value Measurements - Additional Information (Details) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value assets transfer from Level 1 to Level 2	$ 0
Fair value assets transfer from Level 2 to Level 1	0
Fair value liabilities transfer from Level 1 to Level 2	0
Fair value liabilities transfer from Level 2 to Level 1	0
Level 3 [Member] | Fair Value on a Nonrecurring Basis [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 0	$ 0

XML

Fair Value Measurements - Summary of Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Financial assets
Current derivative assets	$ 3,626	$ 3,569
Noncurrent derivative assets	287
Fair Value on a Recurring Basis [Member]
Financial assets
Current derivative assets	3,626	3,569
Noncurrent derivative assets	287
Net Recognized Assets	3,913	3,569
Fair Value on a Recurring Basis [Member] | Level 2 [Member]
Financial assets
Current derivative assets	3,626	3,569
Noncurrent derivative assets	287
Net Recognized Assets	$ 3,913	$ 3,569

XML

Derivative Financial Instruments

9 Months Ended

Sep. 30, 2015

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

Note 3. Derivative Financial Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815 Derivatives and Hedging (“ASC Topic 815”), to account for its derivative financial instruments. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The counterparties to the Company’s current derivative contracts are lenders in the Company’s credit agreement, which is described in Note 6 Long-Term Debt below. The Company did not post collateral under any of these contracts as they are secured under the Company’s credit agreement with the same counterparties.

The Company’s crude oil and natural gas derivative positions are swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain on derivative contracts” on the Condensed Consolidated Statements of Operations. All derivative contracts are recorded at their fair market value and are included in the Company’s Condensed Consolidated Balance Sheets as assets or liabilities.

With an individual derivative counterparty, the Company may have multiple hedge positions that expire at various points in the future and result in fair value asset and liability positions. At the end of each reporting period, those positions are offset to a single fair value asset or liability for each commodity per counter party, and the netted balance is reflected in the Company’s Consolidated Balance Sheets as an asset or a liability.

The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

The Company had the following open crude oil derivative contracts as of September 30, 2015:

Period	Instrument	Commodity	Volume in Bbls		Fixed Price
October 2015 - December 2015	Swap	Crude Oil		16,500	$	95.10
October 2015 - March 2016	Swap	Crude Oil		30,000	$	57.00
October 2015 - June 2016	Swap	Crude Oil		90,000	$	58.00
October 2015 - December 2016	Swap	Crude Oil		150,000	$	60.80

The following table summarizes the location and fair value amounts of all derivative instruments in the Condensed Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Condensed Consolidated Balance Sheets (in thousands):

		September 30, 2015						December 31, 2014
Derivatives not designated as hedging contracts under ASC Topic 815	Balance Sheet Location	Gross Recognized Assets / Liabilities		Gross Amounts Offset		Net Recognized Assets / Liabilities		Gross Recognized Assets / Liabilities		Gross Amounts Offset		Net Recognized Assets / Liabilities
Commodity contracts	Current derivative assets	$	3,626	$	—	$	3,626	$	3,569	$	—	$	3,569
Commodity contracts	Noncurrent derivative assets	$	287	$	—	$	287	$	—	$	—	$	—

The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative instruments in the Company’s Condensed Consolidated Statements of Operations (in thousands):

		Three months ended September 30,				Nine months ended September 30,
Derivatives not designated as hedging contracts under ASC Topic 815	Statement of Operations Location	2015		2014		2015		2014
Unrealized gain on commodity    contracts	Net gain on derivative contracts	$	3,425	$	2,369	$	344	$	1,155
Realized gain (loss) on commodity    contracts	Net gain on derivative contracts	$	1,741	$	120	$	4,178	$	(969	)
		$	5,166	$	2,489	$	4,522	$	186

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Earnings (Loss) Per Common Share - Reconciliation of Net (Loss) Income and Weighted-Average Shares of Common Stock Outstanding for Calculating Basic and Diluted (Loss) Income Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Share [Abstract]
Net income (loss)	$ 1,718	$ 4,214	$ (144)	$ 8,484
Weighted average common shares outstanding:
Basic	13,835,128	9,124,452	13,835,128	9,124,452
Diluted	13,835,128	9,124,452	13,835,128	9,124,452
Net income (loss) per common share:
Basic	$ 0.12	$ 0.46	$ (0.01)	$ 0.93
Diluted	$ 0.12	$ 0.46	$ (0.01)	$ 0.93

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 41,327	$ 100,447
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	15,828	14,016
Joint interest billings and other	6,370	9,417
Prepaid expenses and other current assets	1,058	1,578
Current derivative assets	3,626	3,569
Total current assets	68,209	129,027
Oil and gas properties, successful efforts method:
Proved properties	365,584	317,006
Unproved properties	85,971	76,791
Total oil and gas properties	451,555	393,797
Accumulated depreciation, depletion, and amortization	(111,530)	(97,920)
Net oil and gas properties	340,025	295,877
Other noncurrent assets:
Goodwill	22,992	22,992
Office and other equipment, less accumulated depreciation of $879 and $474 at September 30, 2015 and December 31, 2014	2,032	2,109
Land	101	101
Noncurrent derivative assets	287
Other noncurrent assets	1,184	1,282
TOTAL ASSETS	434,830	451,388
Current liabilities:
Accounts payable	23,662	28,753
Accrued expenses	16,454	20,529
Revenues and royalties payable	9,947	17,364
Advances	21,600	21,398
Asset retirement obligations	341	408
Total current liabilities	72,004	88,452
Noncurrent liabilities:
Long-term debt	11,191	11,191
Asset retirement obligations	5,822	5,670
Deferred tax liability	29,188	29,258
Other noncurrent liabilities	241	289
Total noncurrent liabilities	46,442	46,408
Total liabilities	$ 118,446	$ 134,860
Commitments and Contingencies (Note 10)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding
Common stock, $0.001 par value, 100,000,000 shares authorized; 13,835,128 shares issued and outstanding at September 30, 2015 and December 31, 2014	$ 14	$ 14
Additional paid-in capital	358,086	358,086
Accumulated deficit	(41,256)	(41,112)
Treasury stock, 15,414 shares at September 30, 2015 and December 31, 2014	(460)	(460)
Total equity	316,384	316,528
TOTAL LIABILITIES AND EQUITY	$ 434,830	$ 451,388

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Basis of Presentation

Note 1. Basis of Presentation

Earthstone Energy, Inc., a Delaware corporation (“Earthstone” or the “Company”) is an independent oil and gas exploration and production company engaged in the acquisition, development, exploration and production of onshore, unconventional reserves, with a current focus on the Eagle Ford trend of South Texas and the Bakken trend of North Dakota and Montana. The Company also has conventional wells in East Texas, South Texas and Oklahoma.

The accompanying unaudited consolidated financial statements of Earthstone and our wholly-owned subsidiaries, which we refer to as “we,” “our” or “us,” have been prepared in accordance with Article 8-03 of Regulation S-X for interim financial statements required to be filed with the Securities and Exchange Commission (“SEC”).  The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's Condensed Consolidated Balance Sheets as of September 30, 2015, and December 31, 2014; the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014; and the Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014.  The Company’s balance sheet at December 31, 2014 is derived from the audited consolidated financial statements at that date.

The preparation of financial statements in conformity with the generally accepted accounting principles of the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. For further information, see Note 2 in the Notes to Consolidated Financial Statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014.

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements and the accompanying notes prepared in accordance with GAAP, has been condensed or omitted. These financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and the Company’s other filings with the SEC.  The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

On December 19, 2014, the Company acquired three operating subsidiaries of Oak Valley Resources, LLC (“OVR”), in exchange for shares of Earthstone common stock (the “Exchange”), which resulted in a change of control of the Company. Pursuant to the Exchange Agreement, OVR contributed to Earthstone the membership interests of its three subsidiaries, Oak Valley Operating, LLC (“OVO”), EF Non-Op, LLC (“EF Non-Op”) and Sabine River Energy, LLC (“Sabine”), each a Texas limited liability company (collectively “Oak Valley”), in exchange for approximately 9.124 million shares, representing 84% of the Company’s common stock.  The transaction was accounted for as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes.  All historical financial information, prior to December 19, 2014, contained in this Quarterly Report on Form 10-Q is that of Oak Valley.

Immediately following the Exchange, the Company, through its acquired wholly owned subsidiary, Sabine, acquired an additional 20% undivided ownership interest in certain crude oil and gas properties located in Fayette and Gonzales Counties, Texas, in exchange for the issuance of approximately 2.957 million shares of common stock (the “Contribution Agreement”) to Flatonia Energy, LLC, increasing the Company’s ownership in these properties from a 30% undivided ownership to a 50% undivided ownership interest.  As a result of the share issuance to Flatonia, OVR’s ownership in the Company decreased from 84% to 66%.

Recently Issued Accounting Standards

Revenue Recognition - In May 2014, the Financial Accounting Standards Board (“FASB”) issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its consolidated financial statements.

Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements.  Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset.  Amortization of the costs is reported as interest expense.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  The Company will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods.  The Company does not expect the adoption of this new presentation guidance to have a material impact on its consolidated balance sheets.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination.  The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.  The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015 with early adoption permitted.  The Company will adopt this standard update, as required, beginning with the first quarter of 2016, and does not expect it to have a material impact on its consolidated financial statements.  

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Asset Retirement Obligations - Additional Information (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	$ 341	$ 408

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Basis of Presentation - Additional Information (Details)		9 Months Ended
	Dec. 19, 2014 Subsidiary shares	Sep. 30, 2015 shares
Oak Valley Resources, Limited Liability Company [Member]
Basis Of Presentation [Line Items]
Number of subsidiaries acquired | Subsidiary	3
Common stock shares issued in exchange for acquisition	9,124,452
Percentage of common stock acquired	84.00%	66.00%
Flatonia Energy, LLC [Member]
Basis Of Presentation [Line Items]
Additional ownership interest acquired in certain oil and gas properties		20.00%
Common stock shares issued in exchange for acquisition		2,957,000
Undivided ownership interest percentage before acquisition		30.00%
Undivided ownership interest percentage after acquisition		50.00%

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Related Party Transactions - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Oak Valley Management Limited Liability Company [Member]
Related Party Transaction [Line Items]
General and administrative expenses related to services	$ 0.8	$ 0.8	$ 3.0	$ 2.9
Oak Valley Resources, Limited Liability Company [Member]
Related Party Transaction [Line Items]
Accounts payable, related parties	$ 1.0		$ 1.0		$ 2.3

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Acquisitions and Divestitures - Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended
	Dec. 19, 2014	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Total shares of Common Stock outstanding following the Exchange			13,835,128	13,835,128
Estimated Fair Value of Assets Acquired:
Goodwill			$ 22,992	$ 22,992
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Shares of Common Stock outstanding before the Exchange	1,734,988
Company director and officer restricted shares that vested in the Exchange	18,400
Shares of Common Stock issued in the Exchange	9,124,452
Total shares of Common Stock outstanding following the Exchange	10,877,840
Shares of Common Stock issued as consideration	1,753,388
Closing price of Common Stock	$ 19.08
Total purchase price	$ 33,455
Estimated Fair Value of Liabilities Assumed:
Current liabilities	7,852
Long-term debt	7,000
Deferred tax liability	2,880
Asset retirement obligation	2,227
Amount attributable to liabilities assumed	19,959
Total purchase price plus liabilities assumed	53,414
Estimated Fair Value of Assets Acquired:
Cash	2,920
Other current assets	3,466
Other non-current assets	745
Amount attributable to assets acquired	34,468
Goodwill	18,946
Earthstone Energy Reverse Acquisition [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	21,813
Earthstone Energy Reverse Acquisition [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	$ 5,524
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Shares of Common Stock issued as consideration in the Contribution	2,957,288
Closing price of Common Stock	$ 19.08
Estimated Fair Value of Liabilities Assumed:
Deferred tax liability	$ 4,046
Asset retirement obligation	173
Amount attributable to liabilities assumed	4,219
Total purchase price plus liabilities assumed	60,644
Estimated Fair Value of Assets Acquired:
Amount attributable to assets acquired	56,598
Goodwill	4,046
Consideration paid	56,425
2014 Eagle Ford Properties [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	34,745
2014 Eagle Ford Properties [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties	$ 21,853
Other Acquisitions [Member]
Estimated Fair Value of Liabilities Assumed:
Asset retirement obligation		$ 13
Amount attributable to liabilities assumed		18
Other liabilities		5
Total purchase price plus liabilities assumed		4,066
Estimated Fair Value of Assets Acquired:
Amount attributable to assets acquired		4,084
Consideration paid		4,066
Other Acquisitions [Member] | Proved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		588
Other Acquisitions [Member] | Unproved Oil and Gas Properties [Member]
Estimated Fair Value of Assets Acquired:
Oil and natural gas properties		$ 3,496

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2015

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 2. Acquisitions and Divestitures

Earthstone Energy Reverse Acquisition

On December 19, 2014, the Company and OVR closed the Exchange. In this transaction, OVR contributed to the Company the membership interests of its three wholly-owned subsidiaries, which included producing assets, undeveloped acreage and cash.  OVR received approximately 9.124 million shares of newly issued common stock, $0.001 par value per share (the “Common Stock”), of the Company. The Exchange resulted in a change of control of the Company. The Exchange has been accounted in accordance with FASB Accounting Standards Codification (“ASC”)805, Business Combinations (“ASC 805”) as a reverse acquisition whereby Oak Valley is considered the acquirer for accounting purposes although Earthstone is the acquirer for legal purposes. ASC 805 also requires, that among other things, assets acquired and liabilities assumed to be measured at their acquisition date fair values. The results of operations from Earthstone’s legacy assets are reflected in the Company’s consolidated statement of operations beginning December 19, 2014.

An allocation of the purchase price was prepared using, among other things, the 2014 year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to the December 19, 2014 acquisition date. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Earthstone tax return and certain accruals and includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.

The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets (in thousands, except share and share price amounts):

Shares of Common Stock outstanding before the Exchange		1,734,988
Company director and officer restricted shares that vested    in the Exchange		18,400
Shares of Common Stock issued in the Exchange		9,124,452
Total shares of Common Stock outstanding following the    Exchange		10,877,840
Shares of Common Stock issued as consideration		1,753,388
Closing price of Common Stock (1)	$	19.08
Total purchase price	$	33,455
Estimated Fair Value of Liabilities Assumed:
Current liabilities	$	7,852
Long-term debt		7,000
Deferred tax liability (2)		2,880
Asset retirement obligation		2,227
Amount attributable to liabilities assumed		19,959
Total purchase price plus liabilities assumed	$	53,414
Estimated Fair Value of Assets Acquired:
Cash (3)	$	2,920
Other current assets		3,466
Proved oil and natural gas properties (4) (5)		21,813
Unproved oil and natural gas properties		5,524
Other non-current assets		745
Amount attributable to assets acquired	$	34,468
Goodwill (6)	$	18,946

(1) The share price used for the determination of the purchase price was $19.08, which was the closing price of the Common Stock on December 19, 2014.

(2) This amount represents the recorded book value versus tax value difference in oil and natural gas properties and other net assets as of the date of the Exchange on a tax effected basis of approximately 35%. The tax basis of the legacy Earthstone assets were not adjusted in the Exchange. As noted above, however, ASC 805 requires that the Company in a reverse acquisition record the legacy Earthstone net assets at fair value on the date of the Exchange; the fair value of the net assets was in excess of the tax basis and as such required the recognition of a deferred tax liability.

(3) The components of cash flow in the Exchange in which the legacy Earthstone assets were acquired were $7.1 million in notes payable and accrued interest that was paid in full in conjunction with the Exchange less the cash acquired of $2.9 million.

(4) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $51.62 per barrel of oil and $4.58 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.     

(5) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projections of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4 Fair Value Measurements, below.

(6) Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. The goodwill recognized will not be deductible for tax purposes.

2014 Eagle Ford Acquisition Properties

Also on December 19, 2014, immediately following the Exchange, Flatonia Energy, LLC (“Flatonia”), Parallel Resource Partners, LLC (“Parallel”), and Sabine, closed the transactions contemplated by the Contribution Agreement by and among the Company, OVR, Sabine, Oak Valley Operating, LLC, Parallel, and Flatonia, whereby Parallel contributed 28.57% of the oil and natural gas property interests held by Flatonia, a wholly owned subsidiary of Parallel, in consideration for approximately 2.96 million shares of Common Stock (the “Contribution”). The assets subject to the Contribution Agreement were oil and natural gas property interests in producing wells and acreage in the Eagle Ford trend of Texas (the “2014 Eagle Ford Acquisition Properties”). One of the subsidiaries included in the Exchange is the operator of the 2014 Eagle Ford Acquisition Properties. The only relationship that Flatonia or Parallel had with this subsidiary or the Company prior to the transaction was that the subsidiary is the operator of the 2014 Eagle Ford Acquisition Properties. The Contribution was accounted for as a business combination in accordance ASC 805 which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date. 

An allocation of the purchase price was prepared using, the 2014 year-end reserve report prepared by Cawley, Gillespie and Associates, Inc. that was adjusted and re-priced by the Company’s reserve engineering staff back to December 19, 2014. The following allocation is still preliminary with respect to final tax amounts, pending the completion of the 2014 Flatonia tax return and certain accruals and it includes the use of estimates based on information that was available to management at the time these consolidated financial statements were prepared. The Company’s final allocation of purchase price is dependent on the seller’s tax return since Earthstone received carryover basis on Flatonia’s assets and liabilities because the Contribution Agreement was not a taxable transaction under the United States Internal Revenue Code of 1986, as amended. Additional changes to the purchase price allocation may result in a corresponding change to goodwill in the period of the change.

The following table summarizes the consideration paid to acquire the 2014 Eagle Ford Acquisition Properties and the estimated values of those net assets (in thousands, except share and share price amounts):

Shares of Common Stock issued as consideration in    the Contribution		2,957,288
Closing price of Common Stock (1)	$	19.08
Total purchase price	$	56,425
Estimated Fair Value of Liabilities Assumed:
Deferred tax liability (2)	$	4,046
Asset retirement obligation		173
Amount attributable to liabilities assumed		4,219
Total purchase price plus liabilities assumed	$	60,644
Estimated Fair Value of Assets Acquired:
Proved oil and natural gas properties (3) (4)	$	34,745
Unproved oil and natural gas properties		21,853
Amount attributable to assets acquired	$	56,598
Goodwill (5)	$	4,046

(1) The share price used for the determination of the purchase price was $19.08, which was the closing price of the Common Stock on December 19, 2014.

(2) This amount represents the recorded book value to tax difference in the oil and natural gas properties as of the date of the Contribution Agreement on a tax effected basis of approximately 34%. As noted above, the Company received the net assets at Flatonia’s carryover tax basis and as such requires the recognition of a deferred tax liability.

(3) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $56.36 per barrel of oil and $3.36 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.     

(4) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projecting of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4 Fair Value Measurements, below.

(5) Goodwill was determined to be the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. The goodwill recognized will not be deductible for tax purposes.

The following unaudited supplemental pro forma combined condensed results of operations present consolidated information as though the Exchange and Contribution had been completed as of January 1, 2014. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Exchange or Contribution or any estimated costs that will be incurred to integrate the legacy Earthstone net assets and the 2014 Eagle Ford Acquisition Properties. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts).

	Three months ended September 30,		Nine months ended September 30,
	2014		2014
	(Unaudited)
Revenue	$	22,691	$	65,652
Income before taxes	$	10,506	$	26,340
Net income available to Earthstone common    stockholders	$	6,832	$	17,256
Pro forma net income per common share:
Basic and diluted	$	0.49	$	1.25

For the three and nine months ended September 30, 2015, the Company recognized $2.0 million and $7.3 million, respectively, of oil, natural gas and natural gas liquids sales related to the legacy Earthstone assets and operating expenses including depletion of $2.5 million and $8.4 million, respectively. There were no material non-recurring transaction costs related to this acquisition incurred during the three and nine months ended September 30, 2015.

For the three and nine months ended September 30, 2015, the Company recognized $3.2 million and $9.8 million, respectively, of oil, natural gas and natural gas liquids related to the 2014 Eagle Ford Acquisition Properties and operating expenses including depletion of $2.5 million and $7.9 million, respectively. There were no material non-recurring transaction costs related to this acquisition incurred during the three and nine months ended September 30, 2015.

Other Acquisitions

In June 2015, the Company acquired a 50% operated interest in two gross Austin Chalk wells, which hold approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production, with current gross production of 44 barrels of oil equivalent per day (“BOEPD”) all of which was oil.  Also during June 2015, the Company acquired additional acreage in northern Karnes County, Texas, increasing its total leasehold position to approximately 400 gross acres.  The Company currently has a 33% working interest in the Karnes acreage.  These two positions are adjacent to one another and will provide for 17 gross Eagle Ford locations with expected development beginning in the fourth quarter of 2015.

The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands):

Purchase price	$	4,066
Estimated fair value of assets acquired:
Proved oil and natural gas properties	$	588
Unproved oil and natural gas properties		3,496
Total assets acquired	$	4,084
Estimated fair value of liabilities assumed:
Asset retirement obligations	$	13
Other liabilities		5
Total liabilities assumed	$	18
Consideration paid	$	4,066

Pro forma financial information, assuming the acquisition occurred at the beginning of each period presented, has not been presented because the effect on the Company’s results for each of those periods is not material.  The results of the above acquisitions have been included in the Company’s consolidated financials since the date of each acquisition.

In June 2015, the Company acquired additional acreage and increased the Company’s working interest in wells in existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.1 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells.  The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that are in the drilling and completion phase.

In August 2015, the Company acquired a 33% working interest in approximately 1,650 gross acres, in Southern Gonzales County, Texas for $3.3 million. This acreage supports 16 additional gross Eagle Ford locations.  

Divestitures

In April 2015, the Company sold its Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million.  The Company recorded a gain of $1.7 million on the sale.  The effective date of the transaction was March 1, 2015.

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Office and other equipment, accumulated depreciation	$ 879	$ 474
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	13,835,128	13,835,128
Common stock, shares outstanding	13,835,128	13,835,128
Treasury stock, shares	15,414	15,414

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 30, 2015

Earthstone Energy Reverse Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets

The following table summarizes the consideration paid to acquire the legacy Earthstone net assets and the estimated values of those net assets (in thousands, except share and share price amounts):

Shares of Common Stock outstanding before the Exchange		1,734,988
Company director and officer restricted shares that vested    in the Exchange		18,400
Shares of Common Stock issued in the Exchange		9,124,452
Total shares of Common Stock outstanding following the    Exchange		10,877,840
Shares of Common Stock issued as consideration		1,753,388
Closing price of Common Stock (1)	$	19.08
Total purchase price	$	33,455
Estimated Fair Value of Liabilities Assumed:
Current liabilities	$	7,852
Long-term debt		7,000
Deferred tax liability (2)		2,880
Asset retirement obligation		2,227
Amount attributable to liabilities assumed		19,959
Total purchase price plus liabilities assumed	$	53,414
Estimated Fair Value of Assets Acquired:
Cash (3)	$	2,920
Other current assets		3,466
Proved oil and natural gas properties (4) (5)		21,813
Unproved oil and natural gas properties		5,524
Other non-current assets		745
Amount attributable to assets acquired	$	34,468
Goodwill (6)	$	18,946

(1) The share price used for the determination of the purchase price was $19.08, which was the closing price of the Common Stock on December 19, 2014.

(2) This amount represents the recorded book value versus tax value difference in oil and natural gas properties and other net assets as of the date of the Exchange on a tax effected basis of approximately 35%. The tax basis of the legacy Earthstone assets were not adjusted in the Exchange. As noted above, however, ASC 805 requires that the Company in a reverse acquisition record the legacy Earthstone net assets at fair value on the date of the Exchange; the fair value of the net assets was in excess of the tax basis and as such required the recognition of a deferred tax liability.

(3) The components of cash flow in the Exchange in which the legacy Earthstone assets were acquired were $7.1 million in notes payable and accrued interest that was paid in full in conjunction with the Exchange less the cash acquired of $2.9 million.

(4) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $51.62 per barrel of oil and $4.58 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.     

(5) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projections of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4 Fair Value Measurements, below.

(6) Goodwill was determined to be the excess consideration exchanged over the fair value of the Company’s net assets on December 19, 2014. The goodwill recognized will not be deductible for tax purposes.

2014 Eagle Ford Properties [Member]

Business Acquisition [Line Items]

Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets

The following table summarizes the consideration paid to acquire the 2014 Eagle Ford Acquisition Properties and the estimated values of those net assets (in thousands, except share and share price amounts):

Shares of Common Stock issued as consideration in    the Contribution		2,957,288
Closing price of Common Stock (1)	$	19.08
Total purchase price	$	56,425
Estimated Fair Value of Liabilities Assumed:
Deferred tax liability (2)	$	4,046
Asset retirement obligation		173
Amount attributable to liabilities assumed		4,219
Total purchase price plus liabilities assumed	$	60,644
Estimated Fair Value of Assets Acquired:
Proved oil and natural gas properties (3) (4)	$	34,745
Unproved oil and natural gas properties		21,853
Amount attributable to assets acquired	$	56,598
Goodwill (5)	$	4,046

(1) The share price used for the determination of the purchase price was $19.08, which was the closing price of the Common Stock on December 19, 2014.

(2) This amount represents the recorded book value to tax difference in the oil and natural gas properties as of the date of the Contribution Agreement on a tax effected basis of approximately 34%. As noted above, the Company received the net assets at Flatonia’s carryover tax basis and as such requires the recognition of a deferred tax liability.

(3) The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $56.36 per barrel of oil and $3.36 per Mcf of natural gas after adjustments for transportation fees and regional price differentials.     

(4) The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projecting of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see Note 4 Fair Value Measurements, below.

(5) Goodwill was determined to be the excess consideration exchanged over the fair value of the 2014 Eagle Ford Acquisition Properties on December 19, 2014. The goodwill recognized will not be deductible for tax purposes.

Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed

The following unaudited supplemental pro forma combined condensed results of operations present consolidated information as though the Exchange and Contribution had been completed as of January 1, 2014. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Exchange or Contribution or any estimated costs that will be incurred to integrate the legacy Earthstone net assets and the 2014 Eagle Ford Acquisition Properties. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts).

	Three months ended September 30,		Nine months ended September 30,
	2014		2014
	(Unaudited)
Revenue	$	22,691	$	65,652
Income before taxes	$	10,506	$	26,340
Net income available to Earthstone common    stockholders	$	6,832	$	17,256
Pro forma net income per common share:
Basic and diluted	$	0.49	$	1.25

Other Acquisitions [Member]

Business Acquisition [Line Items]

Schedule of Consideration Paid to Acquire Net Assets and Estimated Values of Net Assets

The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands):

Purchase price	$	4,066
Estimated fair value of assets acquired:
Proved oil and natural gas properties	$	588
Unproved oil and natural gas properties		3,496
Total assets acquired	$	4,084
Estimated fair value of liabilities assumed:
Asset retirement obligations	$	13
Other liabilities		5
Total liabilities assumed	$	18
Consideration paid	$	4,066

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 06, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Trading Symbol	ESTE
Entity Registrant Name	EARTHSTONE ENERGY INC
Entity Central Index Key	0000010254
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		13,835,128

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Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2015

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Schedule of Outstanding Commodity Derivative Instruments

The Company had the following open crude oil derivative contracts as of September 30, 2015:

Period	Instrument	Commodity	Volume in Bbls		Fixed Price
October 2015 - December 2015	Swap	Crude Oil		16,500	$	95.10
October 2015 - March 2016	Swap	Crude Oil		30,000	$	57.00
October 2015 - June 2016	Swap	Crude Oil		90,000	$	58.00
October 2015 - December 2016	Swap	Crude Oil		150,000	$	60.80

Summary of Gross and Net Information about Commodity Derivative Instruments

The following table summarizes the location and fair value amounts of all derivative instruments in the Condensed Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Condensed Consolidated Balance Sheets (in thousands):

		September 30, 2015						December 31, 2014
Derivatives not designated as hedging contracts under ASC Topic 815	Balance Sheet Location	Gross Recognized Assets / Liabilities		Gross Amounts Offset		Net Recognized Assets / Liabilities		Gross Recognized Assets / Liabilities		Gross Amounts Offset		Net Recognized Assets / Liabilities
Commodity contracts	Current derivative assets	$	3,626	$	—	$	3,626	$	3,569	$	—	$	3,569
Commodity contracts	Noncurrent derivative assets	$	287	$	—	$	287	$	—	$	—	$	—

Realized and Unrealized Gains and Losses from Commodity Derivative Instruments

The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative instruments in the Company’s Condensed Consolidated Statements of Operations (in thousands):

		Three months ended September 30,				Nine months ended September 30,
Derivatives not designated as hedging contracts under ASC Topic 815	Statement of Operations Location	2015		2014		2015		2014
Unrealized gain on commodity    contracts	Net gain on derivative contracts	$	3,425	$	2,369	$	344	$	1,155
Realized gain (loss) on commodity    contracts	Net gain on derivative contracts	$	1,741	$	120	$	4,178	$	(969	)
		$	5,166	$	2,489	$	4,522	$	186

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Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Oil, natural gas, and natural gas liquids revenues:
Oil	$ 10,385	$ 8,916	$ 31,586	$ 25,292
Natural gas	1,971	2,113	5,483	7,459
Natural gas liquids	677	928	2,164	2,842
Total oil, natural gas, and natural gas liquids revenues	13,033	11,957	39,233	35,593
Gathering income	60	98	233	293
(Loss) gain on sales of oil and gas properties, net	(13)		1,667
Total revenues	13,080	12,055	41,133	35,886
Production costs:
Lease operating expense	4,138	2,536	12,751	7,210
Severance taxes	746	481	2,122	1,479
Re-engineering and workovers	234	234	520	553
Exploration expense		83	142	83
Depreciation, depletion, and amortization	8,107	5,268	22,705	13,031
General and administrative expense	2,450	1,602	7,505	4,816
Total operating costs and expenses	15,675	10,204	45,745	27,172
(Loss) income from operations	(2,595)	1,851	(4,612)	8,714
OTHER INCOME (EXPENSE)
Interest expense, net	(169)	(149)	(507)	(446)
Net gain on derivative contracts	5,166	2,489	4,522	186
Other income, net	127	23	384	30
Total other income (expense)	5,124	2,363	4,399	(230)
Income (loss) before income taxes	2,529	4,214	(213)	8,484
Income tax expense (benefit)	811		(69)
Net income (loss)	$ 1,718	$ 4,214	$ (144)	$ 8,484
Net income (loss) per common share:
Basic	$ 0.12	$ 0.46	$ (0.01)	$ 0.93
Diluted	$ 0.12	$ 0.46	$ (0.01)	$ 0.93
Weighted average common shares outstanding:
Basic	13,835,128	9,124,452	13,835,128	9,124,452
Diluted	13,835,128	9,124,452	13,835,128	9,124,452

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 7. 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. The accretion of the asset retirement obligation is included in “Lease operating expense” in the Condensed Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.

The following table summarizes the Company’s asset retirement obligation transactions recorded during the nine months ended September 30, 2015, and in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (in thousands):

	2015
Asset retirement obligations at December 31, 2014	$	6,078
Liabilities incurred		104
Accretion expense		425
Property dispositions		(403	)
Liabilities settled		(65	)
Revision of estimates		24
Asset retirement obligations at September 30, 2015	$	6,163

Based on expected timing of settlement, $0.3 million of the asset retirement obligation is classified as current at September 30, 2015.

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Long-Term Debt

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Note 6. Long-Term Debt

On December 19, 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “ESTE Credit Facility”).  The OVR credit facility was refinanced under the ESTE Credit Facility and the legacy credit facility of the Company was paid in full and terminated.

The initial borrowing base of the ESTE Credit Facility was $80.0 million and is subject to redetermination during May and November of each year. At the option of the borrower, the amounts borrowed under the credit agreement bear annual interest rates at either (a) LIBOR plus the applicable utilization margin of 1.50% to 2.50% (1.704% at September 30, 2015) or (b) the base rate plus the applicable utilization margin of 0.50% to 1.50% (3.75% at September 30, 2015). Principal amounts outstanding under the ESTE Credit Facility are due and payable in full at maturity on December 19, 2018. All of the obligations under the credit agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Additional payments due under the credit agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment fee ranges from 0.375% to 0.50% per year, depending upon the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees.

As of September 30, 2015, the Company had $11.2 million of debt outstanding, bearing an interest rate of 1.704%, $0.3 million of letters of credit outstanding and $68.5 million of borrowing base available under its ESTE Credit Facility.

The ESTE Credit Facility contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period.  As of September 30, 2015, the Company was in compliance with these covenants.

Interest expense for the three months ended September 30, 2015 and 2014, includes amortization of deferred financing costs of $65,000 and $38,000, respectively.  Interest expense for the nine months ended September 30, 2015 and 2014, includes amortization of deferred financing costs of $195,000 and $113,000, respectively.  Approximately $1.0 million, net of amortization, associated with the Company’s credit facilities has been capitalized as of September 30, 2015 and December 31, 2014, and was being amortized over the terms of the credit agreements.

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Acquisitions and Divestitures - Additional Information (Details)		1 Months Ended	3 Months Ended		9 Months Ended
	Dec. 19, 2014 USD ($) $ / shares shares	Jun. 30, 2015 USD ($) a Boe Well Location	Sep. 30, 2015 USD ($) a	Sep. 30, 2014 USD ($)	Sep. 30, 2015 USD ($) a Location	Sep. 30, 2014 USD ($)	Apr. 30, 2015 USD ($)
Business Acquisition [Line Items]
Proceeds from oil, natural gas and natural gas liquids			$ 13,033,000	$ 11,957,000	$ 39,233,000	$ 35,593,000
Company acquired gross acres | a			1,650		1,650
Working interest acquired					$ 3,300,000
Cash consideration							$ 3,400,000
Gain (loss) on sale of properties			$ (13,000)		$ 1,667,000
Effective date of transaction					Mar. 01, 2015
Legacy Earthstone [Member]
Business Acquisition [Line Items]
Proceeds from oil, natural gas and natural gas liquids			2,000,000		$ 7,300,000
Operating expenses including depletion			2,500,000		8,400,000
Material non-recurring transaction costs			0		0
Earthstone Energy Reverse Acquisition [Member]
Business Acquisition [Line Items]
Common stock shares issued in exchange for acquisition | shares	9,124,000
Common stock, price per share | $ / shares	$ 0.001
2014 Eagle Ford Properties [Member]
Business Acquisition [Line Items]
Percentage of oil and natural gas property interests held by a wholly owned subsidiary	28.57%
Common stock shares issued in exchange for acquisition | shares	2,957,288
Proceeds from oil, natural gas and natural gas liquids			3,200,000		9,800,000
Operating expenses including depletion			2,500,000		7,900,000
Material non-recurring transaction costs			$ 0		$ 0
Acquisition of working interest					33.00%
Number of locations for eagle ford with expected development | Location					16
Consideration paid	$ 56,425,000
Other Acquisitions [Member]
Business Acquisition [Line Items]
Consideration paid		$ 4,066,000
Other Acquisitions [Member] | Austin Chalk Wells [Member]
Business Acquisition [Line Items]
Acquisition of operating interest		50.00%
Company acquired gross acres | a		1,000
Number of wells acquired | Well		2
Percentage of acres held for production		100.00%
Gross production, barrels of oil equivalents per day | Boe		44
Other Acquisitions [Member] | Northern Kames County [Member]
Business Acquisition [Line Items]
Acquisition of working interest		33.00%
Gross acres acquired | a		400
Number of locations for eagle ford with expected development | Location		17
Other Acquisitions [Member] | Banks Field of McKenzie County [Member]
Business Acquisition [Line Items]
Number of wells acquired | Well		41
Consideration paid		$ 1,400,000
Purchase price adjustment for revenues, net for production taxes, operating expenses and capital costs		$ 2,100,000
Net acres acquired | a		164
Number of drilling wells acquired | Well		21

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Summary of Fair Value of Financial Assets and Liabilities

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):

September 30, 2015	Level 1		Level 2		Level 3		Total
Financial assets
Current derivative assets	$	—	$	3,626	$	—	$	3,626
Noncurrent derivative assets		—		287		—		287
Total financial assets	$	—	$	3,913	$	—	$	3,913
December 31, 2014
Financial assets
Current derivative assets	$	—	$	3,569	$	—	$	3,569
Total financial assets	$	—	$	3,569	$	—	$	3,569

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2015

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 10. Commitments and Contingencies

In the course of its business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state, and local environmental, health and safety laws and regulations and third party litigation.

Commitments

In 2014, the Company entered into an 18 month drilling contract to utilize a new-build drilling rig in its drilling operations.  The new rig is an upgrade and replacement of a rig with a drilling contract that was expiring.  The contract provides for a daily drilling rate of approximately $29,000.  In April 2015, the Company took delivery of the rig and commenced drilling.  As of September 30, 2015, the minimum commitment per the terms of the agreement is approximately $10.9 million. Further, in the event the Company breaks the contract and surrenders the rig, the contract provides for lump sum liquidated damages equal to approximately $20,000 per day through the end of the contract term. As of September 30, 2015 the liquidated damages amount is approximately $7.5 million.  

As a part of the 2013 Eagle Ford Acquisition, the Company and its primary working interest partner in the area ratified several long-term natural gas purchasing and natural gas processing contracts. As is customary in the industry, the Company has reserved gathering and processing capacity in a pipeline. In one of the contracts, the Company and its primary working interest partner have a volume commitment, whereby the owner of the pipeline is paid a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity. Since the time of the acquisition, the volume commitment has not been met. The rate and terms under this purchasing and processing contract expire on June 1, 2021.  As of September 30, 2015, the Company’s share of the remaining commitment on this contract is approximately $4.7 million.

Contingencies

Environmental

The Company’s operations are subject to risks normally associated with the exploration for and the production of oil and natural gas, including blowouts, fires, and environmental risks such as oil spills or natural gas leaks that could expose the Company to liabilities associated with these risks.

In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks.

However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above.

Legal

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. In July 2015, EF Non-Op, LLC, a subsidiary of the Company, filed suit in the 125^th Judicial District Court of Harris County, Texas against the operator of its properties in LaSalle County, Texas. In the case EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP) the Company claims the operator has breached the applicable joint operating agreements in numerous ways, including improper authorization for expenditure requests, improper and imprudent operations, misrepresentation of charges and excessive billings, as well as refusal to provide requested information. The Company also claims damages from negligent representation and fraud.  The Company is seeking all relief to which it is entitled, including consequential damages and attorney’s fees. The outcome of this proceeding is uncertain, and while the Company is confident in its position, any potential monetary recovery to the Company cannot be estimated at this time.

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Related Party Transactions

9 Months Ended

Sep. 30, 2015

Related Party Transactions [Abstract]

Related Party Transactions

Note 8. Related Party Transactions

FASB ASC Topic 850, Related Party Disclosures (“ASC Topic 850”), requires that transactions with related parties that would make a difference in decision making be disclosed so that users of the financial statements can evaluate their significance. Pursuant to ASC Topic 850, OVR and all of its members, most notably Oak Valley Management, LLC (“OVM”) and certain other members (“Certain Other Members of OVR”) are considered related parties.  The following are significant related party transactions between the Company and members of OVM as well as between the Company and Certain Other Members of OVR as of September 30, 2015 and December 31, 2014, and for the three and nine months ended September 30, 2015 and 2014.

The Company employs members of OVM. For each of the three months ended September 30, 2015 and 2014, the Company made payments totaling $0.8 million to these members as compensation for services and reimbursement of expenses. For the nine months ended September 30, 2015 and 2014, the Company made payments totaling $3.0 million and $2.9 million, respectively, to these members as compensation for services and reimbursement of expenses.  The payments are included in “General and administrative expense” on the Condensed Consolidated Statements of Operations or have been charged out to oil and natural gas properties.

The Company has business relationships with Certain Other Members of OVR and with companies that employ Certain Other Members of OVR.  At September 30, 2015 and December 31, 2014, the Company has liabilities of $1.0 million and $2.3 million, respectively, owed to such members and companies.  These amounts are included in “Accounts payable” on the Condensed Consolidated Balance Sheets.

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Income Taxes

9 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Note 9. Income Taxes

For the three months ended September 30, 2015, the Company recorded income tax expense of $0.8 million, and for the nine months ended September 30, 2015, the Company recorded a benefit of $0.1, million both of which were deferred. The Company’s effective tax rate for the three and nine months ended September 30, 2015 was 32.1% and 32.8%, respectively, which is approximately 2% lower than the U.S. Federal statutory corporate income tax rate of 34% due to certain permanent differences.  The effective tax rate also includes approximately 0.9% of the estimated portion of the Company’s income that is subject to income tax in the states in which the Company operates. The Company did not record any tax provision for income tax in the three or nine months ended September 30, 2014 because OVR is a partnership and is not subject to taxation. As explained in Note 1 Basis of Presentation, all historical financial information prior to December 19, 2014 contained in this report is that of OVR and its subsidiaries.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with FASB ASC Topic 740, Income Taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax asset will be realized. The ultimate realization of deferred income tax assets, if any, is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Recently Issued Accounting Standards

Recently Issued Accounting Standards

Revenue Recognition - In May 2014, the Financial Accounting Standards Board (“FASB”) issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods after December 15, 2017; early adoption is permitted as of the original effective date of December 31, 2016. The Company will adopt this standards update, as required, beginning with the first quarter of 2018. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its consolidated financial statements.

Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements.  Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset.  Amortization of the costs is reported as interest expense.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  The Company will adopt this standards update, as required, beginning with the first quarter of 2016 and it will be retrospectively applied to all prior periods.  The Company does not expect the adoption of this new presentation guidance to have a material impact on its consolidated balance sheets.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination.  The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.  The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015 with early adoption permitted.  The Company will adopt this standard update, as required, beginning with the first quarter of 2016, and does not expect it to have a material impact on its consolidated financial statements.  

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Asset Retirement Obligations - Summary of Asset Retirement Obligation Transactions (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, Beginning balance	$ 6,078
Liabilities incurred	104
Accretion expense	425	$ 229
Property dispositions	(403)
Liabilities settled	(65)
Revision of estimates	24
Asset retirement obligations, Ending balance	$ 6,163

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Summary of Asset Retirement Obligation Transactions

The following table summarizes the Company’s asset retirement obligation transactions recorded during the nine months ended September 30, 2015, and in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (in thousands):

	2015
Asset retirement obligations at December 31, 2014	$	6,078
Liabilities incurred		104
Accretion expense		425
Property dispositions		(403	)
Liabilities settled		(65	)
Revision of estimates		24
Asset retirement obligations at September 30, 2015	$	6,163

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Acquisitions and Divestitures - Schedule of Unaudited Pro forma Revenues and Expenses of Assets Acquired and Liabilities Assumed (Details) - Earthstone Energy Reverse Acquisition 2014 Eagle Ford Acquisition [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Business Acquisition [Line Items]
Revenue	$ 22,691	$ 65,652
Income before taxes	10,506	26,340
Net income available to Earthstone common stockholders	$ 6,832	$ 17,256
Pro forma net income per common share:
Basic and diluted	$ 0.49	$ 1.25

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Condensed Consolidated Statements of Cash Flows - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities:
Net (loss) income	$ (144,000)	$ 8,484,000
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, and amortization	22,705,000	13,031,000
Unrealized gain on derivative contracts	(344,000)	(1,155,000)
Accretion of asset retirement obligations	425,000	229,000
Deferred income taxes	(69,000)
Amortization of deferred financing costs	195,000	113,000
Settlement of asset retirement obligations	(65,000)	(56,000)
Gain on sale of assets	(1,667,000)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	5,362,000	(18,457,000)
Decrease (increase) in prepaid expenses and other	548,000	(408,000)
(Decrease) increase in accounts payable and accrued expenses	(15,547,000)	38,532,000
(Decrease) increase in revenue and royalties payable	(7,318,000)	10,509,000
Increase in advances	224,000	11,028,000
Net cash provided by operating activities	4,305,000	61,850,000
Cash flows from investing activities:
Acquisitions of oil and gas property	(8,706,000)
Additions to oil and gas property and equipment	(57,705,000)	(54,537,000)
Additions to other property and equipment	(328,000)	(576,000)
Proceeds from sales of oil and gas properties	3,441,000
Net cash used in investing activities	(63,298,000)	(55,113,000)
Cash flows from financing activities:
Deferred financing costs	(127,000)	(188,000)
Net cash used in financing activities	(127,000)	(188,000)
Net (decrease) increase in cash and cash equivalents	(59,120,000)	6,549,000
Cash and cash equivalents at beginning of period	100,447,000	25,423,000
Cash and cash equivalents at end of period	41,327,000	31,972,000
Cash paid for:
Interest	284,000	331,000
Non-cash investing and financing activities:
Asset retirement obligations	128,000	$ 50,000
Acquisitions of oil and gas properties	$ 2,130,000

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Earnings (Loss) Per Common Share

9 Months Ended

Sep. 30, 2015

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share

Note 5. Earnings (Loss) Per Common Share

Basic earnings (loss) per share is computed by dividing net income (loss) attributable to shares of Common Stock by the basic weighted-average shares of Common Stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents.

The following table is a reconciliation of net income and weighted-average shares of Common Stock outstanding for purposes of calculating basic and diluted income per share:

	Three months ended September 30,				Nine months ended September 30,
(In thousands, except share and per share amounts)	2015		2014		2015			2014
Net income (loss)	$	1,718	$	4,214	$	(144	)	$	8,484
Weighted average common shares outstanding:
Basic		13,835,128		9,124,452		13,835,128			9,124,452
Diluted		13,835,128		9,124,452		13,835,128			9,124,452
Net income (loss) per common share:
Basic	$	0.12	$	0.46	$	(0.01	)	$	0.93
Diluted	$	0.12	$	0.46	$	(0.01	)	$	0.93

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Derivative Financial Instruments - Schedule of Open Crude Oil Derivative Contracts (Details) - Swap [Member] - Crude Oil	9 Months Ended
	Sep. 30, 2015 $ / bbl bbl
October 2015 - December 2015 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	16,500
Fixed Price, Bbls	95.10
October 2015 - March 2016 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	30,000
Fixed Price, Bbls	57.00
October 2015 - June 2016 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	90,000
Fixed Price, Bbls	58.00
October 2015 - December 2016 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	150,000
Fixed Price, Bbls	60.80

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Commitments and Contingencies - Additional Information (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2015 USD ($) MMBTU $ / MMBTU	Dec. 31, 2014 USD ($)
Natural Gas Purchasing and Natural Gas Processing Contract [Member]
Loss Contingencies [Line Items]
Pipeline fee paid | $ / MMBTU	0.45
Holding pipeline capacity | MMBTU	10,000
Purchasing and processing contract expiry date	Jun. 01, 2021
Company's share of remaining commitment amount	$ 4,700,000
Drilling Commitments
Loss Contingencies [Line Items]
Daily drilling rate of wells		$ 29,000
Commitment amount	7,500,000
Minimum commitment per terms of the agreement	$ 10,900,000
Drilling Rigs Contract Period	18 months
Liquidated damages per day	$ 20,000

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Earnings (Loss) Per Common Share (Tables)

9 Months Ended

Sep. 30, 2015

Earnings Per Share [Abstract]

Reconciliation of Net (Loss) Income and Weighted-Average Shares of Common Stock Outstanding for Calculating Basic and Diluted (Loss) Income Per Share

The following table is a reconciliation of net income and weighted-average shares of Common Stock outstanding for purposes of calculating basic and diluted income per share:

	Three months ended September 30,				Nine months ended September 30,
(In thousands, except share and per share amounts)	2015		2014		2015			2014
Net income (loss)	$	1,718	$	4,214	$	(144	)	$	8,484
Weighted average common shares outstanding:
Basic		13,835,128		9,124,452		13,835,128			9,124,452
Diluted		13,835,128		9,124,452		13,835,128			9,124,452
Net income (loss) per common share:
Basic	$	0.12	$	0.46	$	(0.01	)	$	0.93
Diluted	$	0.12	$	0.46	$	(0.01	)	$	0.93