EARTHSTONE ENERGY INC - Quarter Report: 2016 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended September 30, 2016

☐	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 ☒ No ☐

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 ☒ No ☐

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	☐	Accelerated filer	☒

Non-accelerated filer	☐ (Do not check if a smaller reporting company)	Smaller reporting company	☐

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

As of November 4, 2016, 22,289,177 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, 2016 and December 31, 2015	5
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2016 and 2015	6
	Condensed Consolidated Statement of Equity for the Nine Months Ended September 30, 2016	7
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	35
	Signatures	36

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, 2015, 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”);

•

substantial changes in estimates of our proved reserves;

•

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

•

our ability to replace 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 and quality services and supplies on a timely basis and at reasonable prices;

•

the cost and availability of high quality goods and services with fully trained and adequate personnel, 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 including mechanical failures;

•

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;

•

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

•

our ability to retain key members of senior management and key technical and financial 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 or unavailable;

•

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 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 non-operated working interests.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,			December 31,
ASSETS	2016			2015
Current assets:	(In thousands, except share amounts)
Cash and cash equivalents	$	23,809		$	23,264
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues		9,205			13,529
Joint interest billings and other		2,108			4,924
Prepaid expenses and other current assets		2,376			498
Current derivative asset		185			3,694
Total current assets		37,683			45,909
Oil and gas properties, successful efforts method:
Proved properties		348,408			283,644
Unproved properties		59,942			34,609
Total oil and gas properties		408,350			318,253

Accumulated depreciation, depletion, and amortization		(135,823	)		(119,920	)
Net oil and gas properties		272,527			198,333
Other noncurrent assets:
Goodwill		20,549			17,532
Office and other equipment, less accumulated depreciation of $1,426 and $1,028 at September 30, 2016 and December 31, 2015		1,605			1,934
Other noncurrent assets		1,112			1,236
TOTAL ASSETS	$	333,476		$	264,944
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	12,529		$	11,580
Accrued expenses		10,445			12,975
Revenues and royalties payable		6,846			8,576
Advances		6,481			15,447
Current portion of long-term debt		1,591			—
Current derivative liability		1,237			—
Total current liabilities		39,129			48,578

Noncurrent liabilities:
Long-term debt		13,104			11,191
Asset retirement obligations		5,815			5,075
Noncurrent derivative liability		1,101			—
Deferred tax liability		1,051			—
Other noncurrent liabilities		183			227
Total noncurrent liabilities		21,254			16,493

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; 22,289,177 and 13,835,128 shares issued and outstanding at September 30, 2016 and December 31, 2015		23			14
Additional paid-in capital		452,790			358,086
Accumulated deficit		(179,260	)		(157,767	)
Treasury stock, 15,357 shares at September 30, 2016 and December 31, 2015		(460	)		(460	)
Total equity		273,093			199,873

TOTAL LIABILITIES AND EQUITY	$	333,476		$	264,944

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
REVENUES	(In thousands, except share and per share amounts)
Oil, natural gas, and natural gas liquids revenues:
Oil	$	8,262		$	10,385		$	21,898		$	31,586
Natural gas		1,417			1,971			3,376			5,483
Natural gas liquids		851			677			1,843			2,164
Total oil, natural gas, and natural gas liquids revenues		10,530			13,033			27,117			39,233
Gathering income		55			60			142			233
Gain (loss) on sales of oil and gas properties, net		8			(13	)		8			1,667
Total revenues		10,593			13,080			27,267			41,133
OPERATING COSTS AND EXPENSES
Production costs:
Lease operating expense		3,981			4,138			10,248			12,751
Severance taxes		522			746			1,418			2,122
Rig idle and contract termination expense		—			—			5,059			—
Depreciation, depletion, and amortization		5,149			8,107			16,252			22,705
Re-engineering and workovers		798			234			1,379			520
Exploration expense		—			—			5			142
General and administrative expense		3,131			2,450			8,602			7,505
General and administrative expense - stock-based compensation		1,328			—			1,889			—
Total operating costs and expenses		14,909			15,675			44,852			45,745
Loss from operations		(4,316	)		(2,595	)		(17,585	)		(4,612	)
OTHER INCOME (EXPENSE)
Interest expense, net		(341	)		(169	)		(934	)		(507	)
Gain (loss) on derivative contracts, net		946			5,166			(2,517	)		4,522
Other income (expense), net		12			127			(70	)		384
Total other income (expense)		617			5,124			(3,521	)		4,399
(Loss) income before income taxes		(3,699	)		2,529			(21,106	)		(213	)
Income tax expense (benefit)		201			811			387			(69	)
Net (loss) income	$	(3,900	)	$	1,718		$	(21,493	)	$	(144	)
Net (loss) income per common share:
Basic	$	(0.17	)	$	0.12		$	(1.23	)	$	(0.01	)
Diluted	$	(0.17	)	$	0.12		$	(1.23	)	$	(0.01	)
Weighted average common shares outstanding:
Basic		22,289,177			13,835,128			17,433,079			13,835,128
Diluted		22,289,177			13,835,128			17,433,079			13,835,128

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

					Additional
	Common Stock				Paid-in		Accumulated			Treasury Stock						Total
(In thousands, except share amounts)	Shares		Amount		Capital		Deficit			Shares			Amount			Equity
At December 31, 2015		13,835,128	$	14	$	358,086	$	(157,767	)		(15,357	)	$	(460	)	$	199,873

Common stock issued, net of offering costs of $2.7 million		4,753,770		5		47,120		—			—			—			47,125
Stock-based compensation expense		—		—		1,889		—			—			—			1,889
Shares issued in Lynden Arrangement		3,700,279		4		45,695		—			—			—			45,699
Net loss		—		—		—		(21,493	)		—			—			(21,493	)
At September 30, 2016		22,289,177	$	23	$	452,790	$	(179,260	)		(15,357	)	$	(460	)	$	273,093

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities:	(In thousands)
Net loss	$	(21,493	)	$	(144	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization		16,252			22,705
Total loss (gain) on derivative contracts, net		2,517			(4,522	)
Operating portion of net cash received in settlement of derivative contracts		3,330			4,178
Rig idle and termination expense		5,059			—
Accretion of asset retirement obligations		404			425
Stock-based compensation		1,889			—
Deferred income taxes		387			(69	)
Amortization of deferred financing costs		220			195
Settlement of asset retirement obligations		(15	)		(65	)
Gain on sale of assets		(8	)		(1,667	)
Changes in assets and liabilities:
Decrease in accounts receivable		9,141			5,362
(Increase) decrease in prepaid expenses and other		(1,790	)		548
Decrease in accounts payable and accrued expenses		(3,462	)		(15,547	)
Decrease in revenue and royalties payable		(1,730	)		(7,318	)
(Decrease) increase in advances		(8,966	)		224
Net cash provided by operating activities		1,735			4,305
Cash flows from investing activities:
Lynden Arrangement, net of cash acquired		(31,334	)		—
Acquisitions of oil and gas property		—			(8,706	)
Additions to oil and gas property and equipment		(15,272	)		(57,705	)
Additions to other property and equipment		(63	)		(328	)
Proceeds from sales of oil and gas properties		—			3,441
Net cash used in investing activities		(46,669	)		(63,298	)
Cash flows from financing activities:
Proceeds from borrowings		36,597			—
Repayments of borrowings		(38,165	)		—
Issuance of common stock, net of offering costs of $2.7 million		47,125			—
Deferred financing costs		(78	)		(127	)
Net cash provided by (used in) financing activities		45,479			(127	)
Net increase (decrease) in cash and cash equivalents		545			(59,120	)
Cash and cash equivalents at beginning of period		23,264			100,447
Cash and cash equivalents at end of period	$	23,809		$	41,327
Supplemental disclosure of cash flow information
Cash paid for:
Interest	$	688		$	284
Non-cash investing and financing activities:
Common stock issued for Lynden Arrangement	$	45,698		$	—
Acquisitions of oil and gas property	$	—		$	2,130
Asset retirement obligations	$	101		$	128

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Basis of Presentation and Summary of Significant Accounting Policies

Earthstone Energy, Inc., a Delaware corporation (“Earthstone” or the “Company”) is an independent oil and gas exploration and production company focused on the acquisition, development, exploration and production of onshore, crude oil and natural gas reserves, with a current focus on the Eagle Ford trend and Midland Basin in Texas and the Williston Basin of North Dakota and Montana.

The accompanying Unaudited Condensed Consolidated Financial Statements of Earthstone and its wholly-owned subsidiaries, which we refer to as “we,” “our” or “us,” have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to interim financial statements. The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's financial position, results of operations and cash flows for the periods presented. The Company’s Condensed Consolidated Balance Sheet at December 31, 2015 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 periods. 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, 2015 (the “2015 Form 10-K”).

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 2015 Form 10-K, and the Company’s other filings with the SEC.

Certain prior-period amounts have been reclassified to conform to current-period presentation including amounts within the adjustments to reconcile net loss to net cash provided by from operating activities on the Condensed Consolidated Statements of Cash Flows. Specifically, the non-cash changes in fair value of the Company’s commodity swaps have been reclassified from the changes in the Unrealized loss (gain) on derivative contracts caption (which resulted in the caption being eliminated) with offsetting reclassifications to the captions, Total loss (gain) on derivative contracts, net and Operating portion of net cash received in settlement of derivative contracts. These reclassifications had no effect on Net cash provided by operating activities or any other subtotal in the Condensed Consolidated Statements of Cash Flows.

Recently Issued Accounting Standards

Standards adopted in 2016

Debt Issuance Costs – In April 2015, the Financial Accounting Standards Board (“FASB”) issued updated guidance which changes the presentation of debt issuance costs in the financial statements. Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update was effective for interim and annual periods beginning after December 15, 2015. The Company adopted this standards update, as required, effective January 1, 2016. The adoption of this standards update did not affect the Company’s method of amortizing debt issuance costs and did not have a material impact on its Condensed Consolidated Financial Statements.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination. The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standards update was effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The Company adopted this standard update, as required, effective January 1, 2016, which did not have a material impact on its Condensed Consolidated Financial Statements.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Stock Compensation - In March 2016, the FASB issued updated guidance on share-based payment accounting. The standards update is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The standards update is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. The Company elected to early-adopt this standards update as of April 1, 2016 in connection with its initial grant of awards under the Company’s 2014 Long Term Incentive Plan. The Company has elected to record the impact of forfeitures on compensation cost as they occur. The Company is also permitted to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory tax rates. There was no retrospective adjustment as the Company did not have any outstanding equity awards prior to adoption. See Note 6 Stock-Based Compensation.

Standards not yet adopted

Revenue Recognition - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures 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 beginning after December 15, 2017. In March 2016, the FASB issued guidance which clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued further guidance on identifying performance obligations and clarification of the licensing implementation guidance. Early adoption of this updated guidance is permitted as of the original effective date of December 31, 2016. The Company expects to 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 Condensed Consolidated Financial Statements.

Leases – In February 2016, the FASB issued updated guidance on accounting for leases. The update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. Similar to current guidance, the update continues to differentiate between finance leases and operating leases; however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The standards update is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2019. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Condensed Consolidated Financial Statements.

Statement of Cash Flows – In August 2016, the FASB issued updated guidance that clarifies how certain cash receipts and cash payments are presented in the statement of cash flows. This update provides guidance on eight specific cash flow issues. The standards update is effective for interim and annual periods beginning after December 15, 2017, and should be applied retrospectively to all periods presented. Early adoption is permitted. The Company expects to 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 Condensed Consolidated Financial Statements.

Note 2. Acquisitions and Divestitures

Lynden Arrangement

In May 2016, the Company acquired Lynden Energy Corp. (“Lynden”) in an all-stock transaction. The acquisition was made through an arrangement (the “Arrangement”) instead of a merger because Lynden is incorporated in British Columbia, Canada. The Company acquired all the outstanding shares of common stock of Lynden through a newly formed Company subsidiary, with Lynden surviving in the transaction as a wholly-owned subsidiary of the Company. The Company issued 3,700,279 shares of its common stock to the holders of Lynden common stock in the transaction. The Arrangement was accounted for as a business combination in accordance with FASB ASC Topic 805, Business Combinations, 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, among other things, a reserve report prepared by qualified reserve engineers and priced as of the acquisition date. The following allocation is still preliminary with respect to final tax amounts and certain accruals and includes the use of estimates based on information that was available to management at the time these condensed consolidated

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 transferred, fair value of assets acquired and liabilities assumed and resulting goodwill (in thousands, except share and share price amount):

Consideration:
Shares of Earthstone common stock issued in the Arrangement		3,700,279
Closing price of Earthstone common stock as of May 18, 2016	$	12.35
Total consideration to Lynden shareholders	$	45,698
Fair Value of Liabilities Assumed:
Credit facility ⁽⁴⁾	$	36,597
Current liabilities		1,895
Deferred tax liability⁽¹⁾		664
Asset retirement obligations		250
Total consideration plus liabilities assumed	$	85,104
Fair Value of Assets Acquired:
Cash and cash equivalents ⁽⁴⁾	$	5,263
Current assets		2,108
Proved oil and gas properties ⁽²⁾⁽³⁾		48,116
Unproved oil and gas properties		26,600
Amount attributable to assets acquired	$	82,087
Goodwill ⁽⁵⁾	$	3,017

1.	This amount represents the recorded book value to tax difference in the oil and natural gas properties as of the date of the Arrangement on a tax effected basis of approximately 34.5%.

The weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $64.73 per barrel of oil, $3.68 per Mcf of natural gas and $19.34 per barrel of oil equivalent for natural gas liquids, after adjustments for transportation fees and regional price differentials.

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.

4.	Concurrent with closing the Arrangement, the Company paid off the outstanding balance of $36.6 million on the Lynden credit facility. The settlement of the debt and the cash acquired is equal to the $31.3 million net cash outflow associated with the Arrangement.

Goodwill was determined to be the excess consideration exchanged over the fair value of the net assets of Lynden on May 18, 2016. The goodwill resulted from the expected synergies of the management team and balance sheet of the Company combined with the key assets acquired in the Midland Basin area. The goodwill recognized will not be deductible for tax purposes.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following unaudited supplemental pro forma condensed results of operations present consolidated information as though the Arrangement had been completed as of January 1, 2015. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for the Company and Lynden and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired, (ii) accretion expense associated with the asset retirement obligations recorded using the Company’s assumptions about the future liabilities and (iii) interest expense based on the combined debt of the Company post-acquisition. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts).

	Three Months Ended September 30,		Nine Months Ended September 30,
	2015		2016			2015
(Unaudited)
Revenue	$	16,473	$	32,677		$	52,792
Income (loss) before taxes	$	1,698	$	(20,603	)	$	142
Income (loss) available to Earthstone common stockholders	$	1,165	$	(21,696	)	$	80
Pro Forma net income (loss) per common share:
Basic and diluted	$	0.07	$	(1.12	)	$	0.00

The results of operations attributable to Lynden are included in our Condensed Consolidated Statements of Operations beginning in May 2016. During the three and nine months ended September 30, 2016, the Company recognized $2.8 million and $4.3 million, respectively, of oil, natural gas and natural gas liquids sales related to the Lynden assets and $2.2 million and $3.1 million, respectively, of operating expenses, inclusive of depletion. During the three and nine months ended September 30, 2016, the Company recognized $0 and $0.7 million, respectively, of non-recurring transaction costs related to this acquisition.

Other Acquisitions

In June 2015, the Company acquired a 50% operated working interests in approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production by two gross Austin Chalk wells with gross production of 44 barrels of oil equivalent per day as of the time of acquisition.

Also during June 2015, the Company acquired 400 gross acres in northern Karnes County, Texas, which is adjacent to the 1,000 gross acres in southern Gonzales County, Texas. Subsequent trades in Karnes County reduced the gross acreage from 400 to 350 gross acres (117 net acres).

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

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

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 Condensed Consolidated Financial Statements since the date of each acquisition.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Additionally, in June 2015, the Company acquired additional acreage and working interest in wells located within existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.0 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells. The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that 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.

Divestitures

In April 2015, the Company sold substantially all of its Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million, recording a gain of $1.6 million. 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, 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 Company did not post collateral under any of these contracts.

The Company’s crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivative contracts, net” on the Condensed Consolidated Statements of Operations. All derivative contracts are recorded at fair market value and are included in the 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 by counterparty, and the netted balance is reflected in the Condensed Consolidated Balance Sheets as an asset or a liability.

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

As of September 30, 2016, the Company had the following open crude oil derivative positions:

	Price Swaps
Period	Commodity	Volume (Bbls)		Weighted Average Price ($/Bbl)
Q4 2016	Crude Oil		135,000	$	49.35
Q1 - Q4 2017	Crude Oil		420,000	$	48.86
Q1 - Q4 2018	Crude Oil		270,000	$	50.70

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

As of September 30, 2016, the Company had the following open natural gas derivative positions:

	Price Swaps
Period	Commodity	Volume (MMBtu)		Weighted Average Price ($/MMBtu)
Q4 2016	Natural Gas		300,000	$	2.604
Q1 - Q4 2017	Natural Gas		1,560,000	$	2.946
Q1 - Q4 2018	Natural Gas		600,000	$	2.907

The following table summarizes the location and fair value amounts of all derivative instruments in the 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, 2016									December 31, 2015
Derivatives not designated as hedging contracts under ASC Topic 815	Balance Sheet Location	Gross Recognized Assets / Liabilities			Gross Amounts Offset			Net Recognized Assets / Liabilities			Gross Recognized Assets / Liabilities		Gross Amounts Offset		Net Recognized Assets / Liabilities
Commodity contracts	Current derivative assets	$	484		$	(299	)	$	185		$	3,694	$	—	$	3,694
Commodity contracts	Current derivative liabilities	$	(1,536	)	$	299		$	(1,237	)	$	—	$	—	$	—
Commodity contracts	Noncurrent derivative liabilities	$	(1,101	)	$	—		$	(1,101	)	$	—	$	—	$	—

The following 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	2016		2015		2016			2015
Unrealized gain (loss) on commodity contracts	Gain (loss) on derivative contracts, net	$	413	$	3,425	$	(5,847	)	$	344
Realized gain on commodity contracts	Gain (loss) on derivative contracts, net	$	533	$	1,741	$	3,330		$	4,178
		$	946	$	5,166	$	(2,517	)	$	4,522

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.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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, 2016.

Fair Value on a Recurring Basis

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

The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the Condensed 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, 2016	Level 1		Level 2			Level 3		Total
Financial assets
Current derivative assets	$	—	$	185		$	—	$	185
Total financial assets	$	—	$	185		$	—	$	185

Financial liabilities
Current derivative liabilities	$	—	$	(1,237	)	$	—	$	(1,237	)
Noncurrent derivative liabilities		—		(1,101	)		—		(1,101	)
Total financial liabilities	$	—	$	(2,338	)	$	—	$	(2,338	)

December 31, 2015
Financial assets
Current derivative assets	$	—	$	3,694		$	—	$	3,694
Total financial assets	$	—	$	3,694		$	—	$	3,694

The carrying amounts of the Company’s other financial instruments, which include cash, accounts receivable, accounts payable, advances and revenues and royalties payable, approximate their respective fair values due to the relatively short-term nature of these instruments. The Company has long-term debt obligations, which consist of a credit facility with a floating interest rate structure, and an unsecured promissory note, with interest rates that are currently available to the Company for debt with similar terms. Both obligations carrying amounts approximate fair value.

Fair Value on a Nonrecurring Basis

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and goodwill. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. Fair value measurements of certain assets acquired and certain liabilities assumed in business combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Asset retirement obligation estimates are derived from historical costs as well as management’s expectations of future cost environments. As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3 as well.

The Company did not recognize any impairment write-downs with respect to its oil and natural gas properties or goodwill during the three and nine months ended September 30, 2016.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 5. Equity

Common Stock Offering

In June 2016, the Company completed a public offering of 4,753,770 shares of common stock (including 253,770 shares purchased pursuant to the underwriters’ overallotment option), at an issue price of $10.50 per share. The Company received net proceeds from this offering of $47.1 million, after deducting underwriters’ fees and offering expenses of $2.7 million. The Company used a portion of the net proceeds from the offering to repay outstanding indebtedness under its revolving credit facility with the remainder held in cash for general corporate purposes.

Earnings (Loss) Per Share

The following table presents the reconciliation of the numerator and denominator for calculating earnings per share (in thousands, except share and per share amounts):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016			2015		2016			2015
Basic EPS:
Net (loss) income	$	(3,900	)	$	1,718	$	(21,493	)	$	(144	)

Weighted average common shares outstanding		22,289,177			13,835,128		17,433,079			13,835,128

Basic (loss) income per common share	$	(0.17	)	$	0.12	$	(1.23	)	$	(0.01	)

Diluted EPS:
Net (loss) income	$	(3,900	)	$	1,718	$	(21,493	)	$	(144	)

Weighted average common shares outstanding		22,289,177			13,835,128		17,433,079			13,835,128
Add: Dilutive effect of restricted stock units		—			—		—			—
Diluted weighted average common shares outstanding		22,289,177			13,835,128		17,433,079			13,835,128

Diluted (loss) income per common share	$	(0.17	)	$	0.12	$	(1.23	)	$	(0.01	)

For the three and nine months ended September 30, 2016, the Company excluded zero and 14,212 shares, respectively for the dilutive effect of restricted stock units in calculating diluted earnings per share as the effect was anti-dilutive due to the net loss incurred for these periods. For the three and nine months ended September 30, 2015, there were no restricted stock units issued or outstanding under the Company’s long-term incentive plan.

Note 6. Stock-Based Compensation

Incentive Plan

In December 2014, the Company’s stockholders approved and adopted, effective on December 19, 2014, the 2014 Long-Term Incentive Plan (the “2014 Plan”), which remains in effect until December 18, 2024. In October 2015, the 2014 Plan was amended to increase the number of shares of the Company’s common stock authorized to be issued. Under the 2014 Plan, the board of directors is authorized to grant stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awards to the Company’s employees or those of its subsidiaries or affiliates as well as persons rendering consulting or advisory services and non-employee directors, subject to the conditions set forth in the 2014 Plan.

The 2014 Plan currently provides that a maximum of 1,500,000 shares of the Company’s common stock may be issued in conjunction with awards granted under the 2014 Plan. Awards that are forfeited or awards settled in cash are available for future issuance under the 2014 Plan. As of September 30, 2016, 727,500 shares of common stock remained available for issuance under the 2014 Plan.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The Company accounts for stock-based compensation in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. The guidance requires that all stock-based payments to employees and directors, including grants of restricted stock units, to be recognized in the financial statements based on their fair values.

Restricted Stock Units

Restricted stock units (“RSUs”) represents a contingent right to receive one share of the Company’s common stock and vest upon satisfaction of the requisite service conditions. Prior to the RSUs vesting, recipients have no ownership interest in the Company’s common stock, no rights to vote and no rights to receive any dividends. The RSUs grant date fair values are based on the Company’s closing common stock price at the date of grant. Expense is recognized on a straight-line basis over the requisite service period of the entire award ensuring compensation cost recognized is consistent with the number of awards vested. Forfeitures are accounted for as they occur through reversal of the previously recognized expense on the awards that were forfeited during the period.

During the nine months ended September 30, 2016, the Company granted 772,500 RSUs with a weighted average grant date fair value of $12.55. The RSUs vest over a 19 or 34 month period with one-third of the award vesting at the end of either seven or 10 months and the remaining two-thirds vesting monthly thereafter. As of September 30, 2016, all 772,500 RSUs were unvested.

For the three and nine months ended September 30, 2016, the Company recognized $1.3 million and $1.9 million, respectively, of stock-based compensation expense. There was no stock-based compensation expense recognized for the comparable periods in 2015. At September 30, 2016, the Company had $7.8 million of unrecognized compensation expense related to unvested RSUs to be recognized over a weighted-average period of 1.4 years.

Note 7. Debt

Credit Facility

In December 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility. At September 30, 2016, the borrowing base under the credit agreement was $75.0 million and is subject to redetermination during May and November of each year. As of September 30, 2016, outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is equal to a base rate (which is equal to the greater of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month LIBOR plus 1.00%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.25% to 2.25% for base rate loans and from 2.25% to 3.25% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee of 0.50% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. The Company is also required to pay customary letter of credit fees. Principal amounts outstanding under the credit 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.

As of September 30, 2016, the Company had a $75.0 million borrowing base, with $10.0 million of debt outstanding, (bearing an interest rate of 2.773%), $0.2 million of letters of credit outstanding, resulting in $64.8 million of borrowing base availability under its credit facility.

The 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 assets, 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, 2016 and December 31, 2015, the Company was in compliance with these covenants under the credit facility.

Promissory Note

In July 2016, the Company issued a $5.1 million unsecured promissory note to a drilling rig contractor in settlement of rig idle charges and the termination amount of the contract. These expenses from late January 2016 through June 2016 were recognized in the Company’s Condensed Consolidated Statement of Operations in the line item Rig idle and contract termination expense. The note amortizes over a three-year period maturing in July 2019, with an annualized interest rate of 8.0% for the first 12 months, 10.0% for the subsequent 12 months, and 12.0% for the last 12 months, with no prepayment penalty. Interest expense will be recognized using

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

the effective interest method of approximately 9.1% over the life of the note. As of September 30, 2016, the Company has $4.7 million outstanding under the note with $1.6 million included in the current portion of long-term debt.

Interest expense for the three and nine months ended September 30, 2016, includes amortization of deferred financing costs of $78,000 and $0.2, million, respectively. Interest expense for the three and nine months ended September 30, 2015, includes amortization of deferred financing costs of $65,000 and $0.2, million, respectively. As of September 30, 2016 and December 31, 2015, $0.7 million and $0.8 million, respectively, of costs, net of amortization, associated with the credit facility have been capitalized. These costs are included in Other noncurrent assets on the Company’s Condensed Consolidated Balance Sheets. The Company’s policy is to capitalize the financing costs associated with the credit agreement and amortize those costs on a straight-line basis over the term of the credit agreement.

Note 8. 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/or the discount rate.

The following table summarizes the Company’s asset retirement obligation transactions recorded during the six months ended September 30, 2016 (in thousands):

	2016
At December 31, 2015	$	5,075
Liabilities incurred		114
Liabilities settled		(15	)
Accretion expense		404
Acquisitions		250
Revision of estimates		(13	)
At September 30, 2016	$	5,815

Note 9. Income Taxes

For the three and nine months ended September 30, 2016, the Company recorded $0.2 million and $0.4 million, respectively of income tax expense related to its Lynden subsidiaries which includes Lynden USA, Inc., a company with taxable income in the United States and its Canadian parent company, Lynden Energy, Inc. (collectively the “Lynden subsidiaries”). The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns. Taxable income of Earthstone, excluding the Lynden subsidiaries cannot be offset by tax attributes, including net operating losses of the Lynden subsidiaries, nor can taxable income of the Lynden subsidiaries be offset by tax attributes of Earthstone, excluding the Lynden subsidiaries. The effective tax rate for both the three and nine months ended September 30, 2016 for the income attributable to the United States Lynden subsidiary was 34.5%, which included approximately 0.5% for the estimated portion of the subsidiary’s income subject to state income tax. The Company, excluding the Lynden subsidiaries, recorded no income tax expense or benefit because property impairments recorded during the year ended December 31, 2015 reduced the book value of the Company’s properties below their tax basis requiring the Company to record a net deferred tax asset. Because the future realization of this deferred tax asset could not be assured, the Company recorded a 100% valuation allowance against its deferred tax asset. The pre-tax loss recorded for the three and nine months ended September 30, 2016, increased the Company’s net deferred tax asset but did not result in a recognized tax benefit because the realization of the Company’s net tax asset still cannot be assured, therefore, the valuation allowance also was increased and offset the tax benefit that would have resulted from the net operating loss. For the three months ended September 30, 2015, the Company recorded an income tax expense of $0.8 million and for the nine months ended September 30, 2015 the company recorded an income tax benefit $69,000; in both cases all of which was deferred. The effective tax rate for both the three and nine month ended September 30, 2015 was 32% which included approximately 0.9% of the estimated portion of the Company’s income subject to income tax in the states in which the Company operates.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 Condensed Consolidated 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.

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

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, 2016, the Company’s share of the remaining commitment on this contract is approximately $3.9 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 accrue to 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.

Legal

From time to time, the Company and its subsidiaries may be involved in various legal proceedings and claims in the ordinary course of business. In July 2015, EF Non-Op, LLC, a subsidiary of the Company, filed suit in the 125^th 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, but not limited to, 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 attorneys’ fees. With respect to a portion of the litigation associated with nine non-operated gas wells that were drilled in 2014 and placed on production in the first half of 2015, BHP Billiton in early 2016 elected to deem the Company as a non-consenting working interest owner regarding costs associated with the drilling, completing and operating of these nine wells, as BHP’s sole and exclusive remedy. The Company has accepted this “non-consent” status. The litigation is continuing with respect to other disputes. The outcome of remaining disputes in 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.

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11. Subsequent Events

On November 7, 2016, the Company entered into a Contribution Agreement (the “Contribution Agreement”), by and among the Company, Earthstone Energy Holdings, LLC, a newly formed Delaware limited liability company (“EEH”), Lynden USA, Inc., a Utah corporation (“Lynden USA”), Lynden USA Operating, LLC, a newly formed Delaware limited liability company (all wholly-owned subsidiaries of the Company), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold”), and Bold Energy III LLC, a Texas limited liability company.

Under the Contribution Agreement, the terms of which were unanimously approved by a special committee of disinterested members of the Company’s Board of Directors and the full Board (i) the Company will recapitalize its common stock into two classes – Class A and Class B, and all of its existing outstanding common stock will be converted into Class A common stock. Bold will purchase 36.1 million shares of the Company’s Class B common stock for nominal consideration, with the Class B common stock having no economic rights in the Company other than voting rights on a pari passu basis with the Class A common stock. In addition, EEH will issue approximately 22.3 million of its membership units to the Company and Lynden USA, in the aggregate, and 36.1 million membership units to Bold in exchange for each of the Company, Lynden USA and Bold transferring all of their assets to EEH; and (iii) Each Bold membership unit in EEH, together with one share of Bold’s Class B common stock, will be convertible into Class A common stock on a one-for-one basis. Therefore, upon the closing of the transaction, stockholders of the Company and unitholders of Bold are expected to own approximately 39% and 61%, respectively of the combined company’s then outstanding Class A and Class B common stock on a fully diluted basis. After closing, the Company will conduct its activities through EEH and be its sole managing member. The transaction is expected to close in the first quarter of 2017 and is subject to approval of the Company’s stockholders and other customary closing conditions.

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 fiscal year ended December 31, 2015. 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 a growth-oriented independent oil and gas company engaged in the development and acquisition of oil and gas reserves through an active and diversified program that includes the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions, and exploration activities, with our current primary assets located in the Eagle Ford trend of South Texas, the Midland Basin of West Texas and in the Williston Basin of North Dakota. 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 to assemble an oil and natural gas reserve base with a market value exceeding its acquisition, development and production costs. Our strategy includes a combination of acquisition, development and exploration activities, typically in more than one basin. Historically, we have shifted our emphasis among basins and these basic activities to take advantage of changing market conditions and to facilitate profitable growth. The majority of our efforts are currently focused on developing our acreage positions in our primary assets. In addition, it is essential that, over time, our personnel expand our current projects and/or generate additional projects so that we have the potential to replace economically our production and increase our proved reserves.

During the first half of 2016, we temporarily suspended drilling and completion operations within our operated assets and reduced general and administrative costs by decreasing our head count and salaries. Generally, employee base salaries were reduced 10% and certain employee benefits were reduced. Further, we do not intend to pay cash bonuses during 2016. The actions we took were in direct response to the low commodity prices and continued uncertainty in the commodities and capital markets. While we believe we have made appropriate adjustments, we have also maintained a positive corporate culture and retained an outstanding staff. Since commodity prices have improved somewhat over the last six months, we restarted completion activities on our operated assets. The following is a brief outline of our current plans:

•

pursue attractive asset or corporate acquisitions;

•

maintain and expand our acreage positions and drilling inventory;

•

pending adequate commodity prices and economics in each area, continue the development of our acreage positions in the Eagle Ford trend, Midland Basin and in the Williston Basin;

•

generate additional exploration and development projects; and

•

obtain additional capital as available and needed, or utilize our common stock for acquisitions.

Commodity Prices:

The upstream oil and natural gas business is cyclical and we are currently operating in a sustained low commodity price environment. Our consolidated average realized prices for the nine months of 2016 decreased 22% for crude oil, 21% for natural gas and 15% for natural gas liquids compared with the same period in 2015. These low prices resulted in a reduction in our capital spending program, had significant negative impacts on our revenues, profitability, cash flows and proved reserves, resulted in asset and goodwill impairments at the end of 2015, and caused us to execute certain cost-saving organizational changes.

During the first nine months of 2016, commodity prices continued to trade in a low range, with crude oil prices falling during the first quarter below $30.00 per barrel on some occasions. Towards the end of the second quarter and into the third quarter prices improved and traded in the $40.00 to $50.00 per barrel range. If the industry downturn continues or prices fall back to where they were in the first quarter, we could experience additional material negative impacts on our revenues, profitability, cash flows, liquidity, and reserves, and we could consider reductions in our capital program. Our production could decline further as a result of these activities.

Acquisitions and Divestitures:

In April 2015, we sold substantially all of our Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million, recording a gain of $1.6 million. The effective date of the transaction was March 1, 2015.

In June 2015, we acquired a 50% operated working interest in approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production from two gross Austin Chalk wells with gross production of 44 barrels of oil per day as of the time of acquisition. This acreage position is expected to support 13 gross Eagle Ford locations.

Also during June 2015, we acquired 400 gross acres in northern Karnes County, Texas, which is adjacent to our 1,000 gross acres in southern Gonzales County, Texas. Subsequent trades in Karnes County reduced the gross acreage from 400 gross acres to 350 gross acres (117 net acres) which has allowed for longer laterals and more efficient development. We initiated drilling on this acreage during the fourth quarter of 2015, with completion of the four wells expected during the second half of 2016.

Additionally, in June 2015, we acquired additional acreage and working interest in wells located within existing Bakken units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.0 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells. The acquisition included 164 net acres which allowed 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 gross Eagle Ford locations.

In May 2016, we acquired Lynden Energy Corp. (“Lynden”) in an all-stock transaction. The acquisition was effected through an arrangement (the “Arrangement”) instead of a merger because Lynden is incorporated in British Columbia, Canada. We acquired all the outstanding shares of common stock of Lynden through a newly formed subsidiary, with Lynden surviving in the transaction as a wholly-owned subsidiary of the Company. We issued 3,700,279 shares of our common stock to the holders of Lynden common stock in the transaction.

Results of Operations

Three Months Ended September 30, 2016, compared to the Three Months Ended September 30, 2015

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, 2016 and 2015, are presented below:

	Three Months Ended September 30,
	2016		2015		Change
Sales volumes:
Oil (MBbl)		201		246		(45	)
Natural gas (MMcf)		563		742		(179	)
Natural gas liquids (MBbl)		71		58		13
Barrels of oil equivalent (MBOE) ⁽¹⁾		366		428		(62	)
Barrels of oil equivalent per day (BOEPD) ⁽¹⁾		3,979		4,646		(667	)

Average prices realized: ⁽²⁾
Oil (Bbl)	$	41.11	$	42.20	$	(1.09	)
Natural gas (Mcf)	$	2.52	$	2.66	$	(0.14	)
Natural gas liquids (Bbl)	$	11.95	$	11.73	$	0.22

	Three Months Ended September 30,
(In thousands)	2016		2015			Change
Oil, natural gas, and natural gas liquids revenues:
Oil	$	8,262	$	10,385		$	(2,123	)
Natural gas		1,417		1,971			(554	)
Natural gas liquids		851		677			174
Other operating revenues:
Gathering income		55		60			(5	)
Gain on sales of oil and gas properties, net		8		(13	)		21
Total revenues	$	10,593	$	13,080		$	(2,487	)

(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 and natural gas liquids 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 have been marked-to-market through our Unaudited Condensed Consolidated Statements 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, 2016, oil revenues decreased by $2.1 million or 20% relative to the comparable period in 2015. Of the decrease, $1.8 million was attributable to decreased volume and $0.3 million was attributable to the decline in our realized price. We had a net decrease in the volume of oil sold of 45 MBbls. Our average realized price per Bbl decreased slightly from $42.20 to $41.11 or 3%. The Midland Basin properties we acquired in the Arrangement provided an additional 49 MBbls and our southern Gonzales and northern Karnes county assets that we acquired and began development on provided an additional 6 MBbls. These increases, however, were offset by declines on our operated Eagle Ford of 71 MBbls, our non-Operated Eagle Ford of 9 MBbls and Bakken/Three Forks properties of 17 MBbls. Our operated Eagle Ford and Bakken/Three Forks properties have newer wells that are still in their initial steeper decline stage. The remaining 3 MBbls net decrease was due to normal production declines and the variability in sales volumes in our other properties mainly in Texas and North Dakota.

Sales of Natural Gas

For the three months ended September 30, 2016, natural gas revenues decreased by $0.6 million or 28% relative to the comparable period in 2015. Of the decrease, $0.5 million was attributable to decreased volumes and $0.1 million was attributable to the decline in our realized price. The volume of natural gas sold decreased by 179 MMcfs. Our average realized price per Mcf decreased from $2.66 to $2.52 or 5%. The Midland Basin properties we acquired in the Arrangement provided an additional 147 MMcfs. These increases were offset by declines on our operated Eagle Ford of 12 MMcfs, our non-operated Eagle Ford of 280 MMcfs, and our non-operated East Texas properties of 27 MMcfs. The significant declines on our non-operated Eagle Ford property primarily results from no longer recognizing revenues on the nine wells that were deemed non-consenting as part of the overall litigation with the operator. For additional information on the litigation with the operator see Note 10 Commitments and Contingencies in the Notes to the Unaudited Condensed Consolidated Financial Statements. The remaining 7 MMcfs decrease was due to production declines and variability in sales volumes in our conventional properties mainly in Texas.

Sales of Natural Gas Liquids

For the three months ended September 30, 2016, natural gas liquids revenues increased by $0.2 million or 26% relative to the comparable period in 2015. The average realized price per Bbl increased from $11.73 to $11.95 or 2%. The volume of natural gas liquids sold increased by 13 MBbl or 22%. The Midland Basin properties we acquired in the Arrangement and our southern Gonzales and northern Karnes county assets that we acquired and began development on provided an additional 29 MBbls. These increases were primary offset by declines on our non-operated Eagle Ford property. As noted above the significant declines on our non-operated Eagle Ford property primarily results from no longer recognizing revenues on the nine wells that we were deemed non-consenting as part of the overall litigation with the operator.

Production Costs

Our production costs for the three months ended September 30, 2016 and 2015 are summarized in the table below:

	Three Months Ended September 30,
(In thousands)	2016			2015			Change
Lease operating expenses	$	3,981		$	4,138		$	(157	)
Severance taxes	$	522		$	746		$	(224	)
Re-engineering and workover expenses	$	798		$	234		$	564

LOE per BOE*	$	9.97		$	9.18		$	0.79

Severance tax as a percent of oil, natural gas and natural gas liquids revenues		4.96	%		5.72	%		-0.76	%

* 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 from other operators provided for in operating agreements.

	Three Months Ended September 30,
(In thousands)	2016		2015		Change
Production related LOE	$	3,650	$	3,924	$	(274	)
Ad valorem taxes		188	$	71		117
Accretion expense		143	$	143		-
Total LOE	$	3,981	$	4,138	$	(157	)

Total LOE, including ad valorem taxes and accretion expense, decreased by $0.2 million or 4% for the three months ended September 30, 2016 relative to the comparable period in 2015. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, increased during the three months ended September 30, 2016 by 9% or $0.79 per BOE due to the decline in oil and natural gas volumes discussed above and a change in the mix of production. We continue to focus on reducing operating costs, economies of scale on our operated Eagle Ford properties, and a decrease in the cost of oil field services in general. Without these efforts LOE on per BOE basis for our properties would have increased more significantly.

Severance Taxes

Severance taxes for the three months ended September 30, 2016 decreased by $0.2 million or 30% relative to the comparable period in 2015, primarily due to the decline in oil and natural gas prices. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes decreased from 5.72% to 4.96%. The decrease was due to the mix of our production. During the three months ended September 30, 2016, a larger portion of our production and revenues were generated from primarily oil wells in Texas, which has lower severance tax rates than several other states.

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 may include surface repairs. These costs increased by $0.6 million during the three months ended September 30, 2016, relative to the comparable period during 2015, 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 (“G&A”)

These expenses consist primarily of employee remuneration, professional and consulting fees and other overhead expenses. G&A increased by $0.6 million from $2.5 million during the three months ended September 30, 2015 to $3.1 million during the three months ended September 30, 2016. Included in the three months ended September 30, 2016 are acquisition related professional costs of $0.8 million related to the acquisition disclosed in Note 11 Subsequent Events in the Notes to the Unaudited Condensed Consolidated Financial Statements. The salary and benefits reductions summarized in the Overview section above partially offset the acquisition related professional fees noted above.

G&A – stock-based compensation during the three months ended September 30, 2016, includes the expense associated with the 2016 grants of restricted stock units (“RSUs”) to employees and non-employee directors. During the three months ended September 30, 2016 we recognized expense of $1.3 million related to the RSU grants. The comparable prior period had no stock-based compensation expense since there were not any previously granted RSUs or other equity based compensation granted.

Depreciation, Depletion and Amortization (“DD&A”)

DD&A decreased for the three months ended September 30, 2016 by $3.0 million, or 36% relative to the comparable period in 2015, due to lower production volumes and reduced net book value in the 2016 period as a result of the significant impairments recognized at the end of 2015. On a per BOE basis, our overall DD&A rate, decreased by $4.90 or 26% from $18.97 during the three months ended September 30, 2015 to $14.07 during the three months ended September 30, 2016, primarily due to the impact of proved property impairments of $94.0 million recorded at the end of 2015. The reserve decreases that led to the impairments were primarily attributable to lower average oil and natural gas prices. In addition, the increase in the mix of production from the Midland Basin properties we acquired in the Arrangement contributed to the DD&A rate decrease for the three months ended September 30, 2016.

Interest Expense

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense was $0.3 million for the three months ended September 30, 2016, as compared to $0.2 million for the three months ended September 30, 2015. The small increase in interest expense was due to the addition of the Promissory Note discussed Note 7 Debt in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Net Gain on Derivative Contracts

During the three months ended September 30, 2016, we recorded a net gain on derivative contracts of $0.9 million, consisting of net gains on settlements of $0.5 million and unrealized mark-to-market net gains of $0.4 million. During the three months ended September 30, 2016, we recorded net settlements related to crude oil contracts of $0.6 million and ($0.1) million related to natural gas contracts. During the three months ended September 30, 2015, we recorded a net gain on derivative contracts of $5.2 million, consisting of net gains on settlements of $1.7 million and unrealized mark-to-market net gains of $3.5 million. During the three months ended September 30, 2015, all of our net settlements related to crude oil contracts.

Income Tax Expense

During the three months ended September 30, 2016, we recorded $0.2 million of income tax expense related to our Lynden subsidiaries, which include Lynden USA, Inc., a company with taxable income in the United States and its Canadian parent company, Lynden Energy, Inc. (collectively the “Lynden subsidiaries”). Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns. Taxable income of Earthstone, excluding the Lynden subsidiaries cannot be offset by tax attributes, including net operating losses of the Lynden subsidiaries, nor can taxable income of the Lynden subsidiaries be offset by tax attributes of Earthstone, excluding the Lynden subsidiaries. The effective tax rate for the income in the United States for the Lynden subsidiaries was 34.5% for the three months ended September 30, 2016. Excluding the Lynden subsidiaries, we recorded no income tax expense or benefit because of property impairments recorded in 2015, which reduced the book value of our properties below our tax basis requiring us to record a net deferred tax asset. Because the future realization of this deferred tax asset could not be assured, we recorded a valuation allowance against our deferred tax asset. The pre-tax loss we recorded for the three months ended September 30, 2016 and other book to tax differences increased our net deferred tax asset but did not result in a recognized income tax benefit because the realization of our net deferred tax asset still cannot be assured; therefore, we increased our valuation allowance and offset the entire deferred tax benefit. 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.

Results of Operations

Nine Months Ended September 30, 2016, compared to the Nine Months Ended September 30, 2015

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, 2016 and 2015, are presented below:

	Nine Months Ended September 30,
	2016		2015		Change
Sales volumes:
Oil (MBbl)		607		684		(77	)
Natural gas (MMcf)		1,593		2,039		(446	)
Natural gas liquids (MBbl)		161		161		-
Barrels of oil equivalent (MBOE) ⁽¹⁾		1,034		1,185		(151	)
Barrels of oil equivalent per day (BOEPD) ⁽¹⁾		3,772		4,340		(568	)

Average prices realized: ⁽²⁾
Oil (Bbl)	$	36.09	$	46.18	$	(10.09	)
Natural gas (Mcf)	$	2.12	$	2.69	$	(0.57	)
Natural gas liquids (Bbl)	$	11.43	$	13.43	$	(2.00	)

	Nine Months Ended September 30,
(In thousands)	2016		2015		Change
Oil, natural gas, and natural gas liquids revenues:
Oil	$	21,898	$	31,586	$	(9,688	)
Natural gas		3,376		5,483		(2,107	)
Natural gas liquids		1,843		2,164		(321	)
Other operating revenues:
Gathering income		142		233		(91	)
Gain on sales of oil and gas properties, net		8		1,667		(1,659	)
Total revenues	$	27,267	$	41,133	$	(13,866	)

(1)

(2)

Sales of Oil

For the nine months ended September 30, 2016, oil revenues decreased by $9.7 million or 31% relative to the comparable period in 2015. Of the decrease, $6.9 million was attributable to the decline in our realized price and $2.8 million was attributable to decreased volumes. Our average realized price per Bbl decreased from $46.18 to $36.09 or 22%. We had a net decrease in the volume of oil sold of 77 MBbls. The Midland Basin properties we acquired in the Arrangement provided an additional 74 MBbls and our southern Gonzales and northern Karnes county assets that we acquired and began development on provided an additional 7 MBbls. These increases, were offset by declines on our operated Eagle Ford of 98 MBbls, our non-operated Eagle Ford of 19 MBbls, and our non-operated Bakken/Three Fork and other northern region properties of 20 MBbls. Our operated Eagle Ford and Bakken/Three Forks properties have newer wells that are still in their initial steeper decline stage. The remaining decrease of 21 MBbls was due to production declines and variability in sales volumes in our conventional properties mainly in Texas.

Sales of Natural Gas

For the nine months ended September 30, 2016, natural gas revenues decreased by $2.1 million or 38% relative to the comparable period during 2015. Of the decrease, $1.2 million was attributable to a decline in our realized price and $0.9 million was attributable to decreased volumes. Our average realized price per Mcf decreased from $2.69 to $2.12 or 21%. The volume of natural gas sold decreased by 446 MMcfs. The Midland Basin properties we acquired in the Arrangement provided an additional 219 MMcfs. These increases however, were offset by declines on our operated Eagle Ford of 17 MMcfs, our non-operated Eagle Ford of 529 MMcfs, and our non-operated East Texas properties of 55 MMcfs. Additionally, the sale of our Louisiana properties resulted in a decrease of 33 MMcfs. The significant declines on our non-operated Eagle Ford property primarily results from no longer recognizing revenues on the nine wells that we were deemed non-consenting as part of the overall litigation with the operator. For additional information on the litigation with the operator see Note 10 Commitments and Contingencies in the Notes to the Unaudited Condensed Consolidated Financial Statements. The remaining 31 MMcfs decrease was due to production declines and variability in sales volumes in our conventional properties mainly in Texas.

Sales of Natural Gas Liquids

For the nine months ended September 30, 2016, natural gas liquids revenues decreased by $0.3 million or 15% relative to the comparable period during 2015. The average realized price per Bbl decreased from $13.43 to $11.43 or 15%. The volume of natural gas liquids sold was consistent with the prior year period.

Production Costs

Our production costs for the nine months ended September 30, 2016 and 2015 are summarized in the table below:

	Nine Months Ended September 30,
(In thousands)	2016			2015			Change
Lease operating expenses	$	10,248		$	12,751		$	(2,503	)
Severance taxes	$	1,418		$	2,122		$	(704	)
Re-engineering and workover expenses	$	1,379		$	520		$	859

LOE per BOE*	$	9.15		$	10.16		$	(1.01	)

Severance tax as a percent of oil, natural gas and natural gas liquids revenues		5.23	%		5.41	%		-0.18	%

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

Lease Operating Expenses

	Nine Months Ended September 30,
(In thousands)	2016		2015		Change
Production related LOE	$	9,458	$	12,033	$	(2,575	)
Ad valorem taxes		386		293		93
Accretion expense		404		425		(21	)
Total LOE	$	10,248	$	12,751	$	(2,503	)

Total LOE, including ad valorem taxes and accretion expense, decreased by $2.5 million or 20% for the nine months ended September 30, 2016 relative to the comparable period in 2015. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, also decreased during the nine months ended September 30, 2016 by 10% or $1.01 per BOE due to our continued focus on reducing operating costs, economies of scale on our operated Eagle Ford property, and a decrease in the cost of oil field services in general.

Severance Taxes

Severance taxes for the nine months ended September 30, 2016 decreased by $0.7 million or 33% relative to the comparable period in 2015, primarily due to the decline in oil and natural gas prices. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained relative flat and decreased by only 3% due to the mix of production and revenues.

Re-engineering and Workovers

Re-engineering and workover expenses increased by $0.9 million during the nine months ended September 30, 2016 relative to the comparable period during 2015 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.

Rig Idle and Contract Termination Expenses

We incurred rig idle and termination expenses of $5.1 million during the nine months ended September 30, 2016. In late January 2016, we suspended drilling and temporarily idled our contracted drilling rig. Our rig contractor agreed to a reduced daily rate of approximately $20,000 per day while the rig was idled. We entered into an agreement with the lessor of the rig to terminate our contract. Per the terms of the agreement, a termination fee for the remaining commitment on the contract was due and the termination fees were retroactively applied back to January 2016, when we suspended our daily drilling and temporarily idled our contracted drilling rig. In connection with the termination at the end of the second quarter, we issued a three-year amortizing promissory note with an original principal amount of $5.1 million, which was equivalent to the unpaid idle charges and the termination fee.

General and Administrative Expenses

These expenses increased by $1.1 million from $7.5 million during the nine months ended September 30, 2015 to $8.6 million during the nine months ended September 30, 2016 primarily due to additional professional and consulting fees of $0.7 million related to the Arrangement and the documenting and testing of controls as required by the Sarbanes-Oxley Act, as well as $0.8 million related to the acquisition disclosed in Note 11 Subsequent Events in the Notes to the Unaudited Condensed Consolidated Financial Statements. The increase in professional and consulting fees was partially offset by the salary and benefits reductions summarized in the Overview section above.

During the nine months ended September 30, 2016 we recognized expense of $1.9 million related to the 2016 RSU grants. The comparable prior period had no stock-based compensation expense since there were not any previously granted RSUs or other equity based compensation.

Depreciation, Depletion and Amortization

DD&A decreased for the nine months ended September 30, 2016 by $6.5 million, or 28% relative to the comparable period in 2015 due to lower production volumes and reduced net book value in the 2016 period as a result of the significant impairments recognized at the end of 2015. On a per BOE basis, our overall DD&A rate, decreased by $3.44 or 18% from $19.16 during the nine months ended September 30, 2015 to $15.72 during the nine months ended September 30, 2016, due to the impact of proved property impairments of $94.0 million recorded at the end of 2015. The reserve decreases that lead to the impairments were primarily attributable to lower average oil and natural gas prices. In addition, the increase in the mix of production from the Midland Basin properties we acquired in the Arrangement contributed to the DD&A rate decrease for the nine months ended September 30, 2016.

Interest Expense

Interest expense for the nine months ended September 30, 2016 was $0.9 million compared to $0.5 million for the comparable period during 2015. During the 2016 period we had higher interest expense charges primarily since we had a higher weighted average debt balance due to the Arrangement and higher amortization of deferred financing costs.

Net (Loss) Gain on Derivative Contracts

During the nine months ended September 30, 2016, we recorded a net loss on derivative contracts of $2.5 million, consisting of net gains on settlements of $3.3 million and unrealized mark-to-market net losses of $5.8 million. During the nine months ended September 30, 2016, we recorded net settlements related to crude oil contracts of $3.2 million and $0.1 million related to natural gas contracts. During the nine months ended September 30, 2015, we recorded a net gain on derivative contracts of $4.5 million, consisting of net gains on settlements of $4.2 million and unrealized mark-to-market net gains of $0.3 million. During the nine months ended September 30, 2015, we recorded net settlements related to crude oil contracts of $4.0 million and $0.2 million related to natural gas contracts.

Income Tax Expense (Benefit)

During the nine months ended September 30, 2016, we recorded $0.4 million of income tax expense related to our Lynden subsidiaries. Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns. Taxable income of Earthstone, excluding the Lynden subsidiaries cannot be offset by tax attributes, including net operating losses of the Lynden subsidiaries, nor can taxable income of the Lynden subsidiaries be offset by tax attributes of Earthstone, excluding the Lynden subsidiaries. The effective tax rate for income in the United States for the Lynden subsidiaries was approximately 34.5% for the nine months ended September 30, 2016. Excluding the Lynden subsidiaries, we have recorded no income tax expense or benefit because of property impairments recorded in 2015, which reduced the book value of our properties below our tax basis requiring us to record a net deferred tax asset. Because the future realization of this deferred tax asset could not be assured, we recorded a valuation allowance against our deferred tax asset. The pre-tax loss we recorded for the nine months ended September 30, 2016 and other book to tax differences increased our net deferred tax asset but did not result in a recognized income tax benefit because the realization of our net deferred tax asset still cannot be assured; therefore, we increased our valuation allowance and offset the entire deferred tax benefit. 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.

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, including the issuance of additional debt and/or equity securities. In addition, we may continue to partially finance our drilling activities through the sale of interest 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.

Common Stock Offering

In June 2016, we completed a public offering of 4,753,770 shares of common stock (including 253,770 shares purchased pursuant to the underwriters’ overallotment option), at an issue price of $10.50 per share. We received net proceeds from this offering of $47.1 million, after deducting underwriters’ fees and offering expenses of $2.7 million. We used $37.8 million of the net proceeds from the offering to partially repay outstanding indebtedness under our revolving credit facility; the majority of which was incurred in connection with the Arrangement.

Senior Secured Revolving Credit Facility and Promissory Note

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. In our latest redetermination, in May 2016, our borrowing base was set at $75.0 million. 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 2.25% to 3.25% or (b) the base rate (which is equal to the greater of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month LIBOR plus 1.00%) plus applicable margin of 1.25% to 2.25%. 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 fee, which is due quarterly, is 0.50% per year on the unused portion of the borrowing base. We are also required to pay customary letter of credit fees. At September 30, 2016, we had approximately $64.8 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, 2016.

In connection with the termination of a drilling rig contract, we entered into a $5.1 million three-year promissory, which has an interest rate for the first year of 8%, 10% for the second year and 12% for the third year and does not contain a prepayment penalty. The initial principal balance on the note was equal to the unpaid idle fees that we previously included in accounts payable and the remaining termination amount of the contract. The idle charges and the termination amount on the rig contract are reflected in operating costs and expenses during the nine months ended September 30, 2016. The current balance on the note is $4.7 million of which $1.6 million is included in current liabilities.

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, 2016 were $1.7 million compared to $4.3 million for the nine months ended September 30, 2015. The net loss, after adjustments for non-cash items, provided cash of $8.5 million for the nine months ended September 30, 2016 compared to $21.0 million in the prior year period, primarily due to the decrease in revenues attributable to lower commodity prices compared to the prior year period. Changes in operating assets and liabilities for the nine months ended September 30, 2016 was $6.8 million compared to $16.7 million in the prior year period. The decreases were primarily related to changes in accounts payable, accrued expenses, advances and revenues and royalties payable associated with reductions of drilling expenditures and revenues distributable. We continue to focus on controlling LOE and other operating costs in seeking to improve our operating cash flows in this sustained historically low and unpredictable commodity price environment, and therefore 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

We had a net cash outflow of $31.3 million related to the Arrangement; which was comprised of a $36.6 million repayment of debt held by Lynden, net of the $5.3 million of cash on hand at the closing of the Arrangement. In 2015, we had a net cash outflow related to the purchase of oil and gas properties of $8.7 million. Cash applied to oil and natural gas properties for the nine months ended September 30, 2016 and 2015 was $15.3 million and $57.7 million, respectively. Cash applied to other non-oil and gas property fixed assets for the nine months ended September 30, 2016 and 2015 was $63,000 and $0.3 million, respectively. In 2015, we sold our Louisiana properties and received net proceeds of $3.4 million. The decrease in cash applied to oil and natural gas properties was primarily due to our curtailment of drilling and completion activities as a result of lower commodity prices.

Cash Flows from Financing Activities

During the nine months ended September 30, 2016 we completed an offering of common stock, as discussed above, in which we received proceeds of $47.1 million, net of offering costs of $2.7 million.

During the nine months ended September 30, 2016, we borrowed $36.6 million under our Credit Agreement to pay off the credit facility of Lynden. Subsequent to our common stock offering, we reduced the outstanding balance on our Credit Agreement to $10.0 million. Also, during the nine months ended September 30, 2016, we made payment on the promissory note signed in connection with the rig termination that reduced the principal on that note by $0.4 million.

We had no significant financing activities for the nine months ended September 30, 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 liability position with a fair value of $2.2 million at September 30, 2016. Based on the published commodity futures price curves for the underlying commodity as of September 30, 2016, a 10% increase in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to decrease by approximately $4.5 million to a net liability of $6.7 million. A 10% decrease in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to increase by approximately $4.8 million to a net asset of $2.6 million. There would also be a similar increase or decrease in “Net gain (loss) on derivative contracts” in the Unaudited Condensed Consolidated Statements of Operations.

Off-Balance Sheet Arrangements

In conjunction with our office lease located in The Woodlands, Texas, we had established letters of credit in the amount of $0.2 million and $0.3 million at September 30, 2016 and December 31, 2015, respectively.

Other than normal operating leases for office space and the letter of credit noted above, we do not have any 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, 2015.

Recently Issued Accounting Standards

Standards adopted in 2016

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 was effective for interim and annual periods beginning after December 15, 2015. The Company adopted this standards update, as required, effective January 1, 2016. The adoption of this standards update did not affect our method of amortizing debt issuance costs and did not have a material impact on our Condensed Consolidated Financial Statements.

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination. The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standards update was effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted. We adopted this standard update, as required, effective January 1, 2016, which did not have a material impact on our Condensed Consolidated Financial Statements.

Stock Compensation - In March 2016, the FASB issued updated guidance on share-based payment accounting. The standards update is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The standards update is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. We elected to early-adopt this standards update as of April 1, 2016 in connection with our initial grant of awards under our 2014 Long Term Incentive Plan. We elected to record the impact of forfeitures on compensation cost as they occur. We are also permitted to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory tax rates. There was no retrospective adjustment as we did not have any outstanding equity awards prior to adoption. See Note 6 Stock-Based Compensation.

Standards not yet adopted

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 beginning after December 15, 2017. In March 2016, the FASB issued guidance which clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued further guidance on identifying performance obligations and clarification of the licensing implementation guidance. Early adoption of this updated guidance 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 the adoption of this guidance on our Condensed Consolidated Financial Statements.

Leases – In February 2016, the FASB issued updated guidance on accounting for leases. This update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. Similar to current guidance, the update continues to differentiate between finance leases and operating leases; however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The standards update is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. We will adopt this standards update, as required, beginning with the first quarter of 2019. We are in the process of evaluating the impact, if any, of the adoption of this guidance on our Condensed Consolidated Financial Statements.

Statement of Cash Flows – In August 2016, the FASB issued updated guidance that clarifies how certain cash receipts and cash payments are presented in the statement of cash flows. This update provides guidance on eight specific cash flow issues. The standards update is effective for interim and annual periods beginning after December 15, 2017, and should be applied retrospectively to all periods presented. Early adoption is permitted. We expect to 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 the adoption of this guidance on our Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.

Commodity Price Risk, Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable. Therefore, we use derivative instruments to provide partial protection against declines in oil and natural gas prices and the adverse effect it could have on our financial condition and operations. The types of derivative instruments that we may choose to utilize include costless collars, swaps, and deferred put options. Our hedge objectives may change significantly as our operational profile changes and/or commodities prices change. Currently, we have hedged only a portion of our anticipated production beyond 2016 due to relatively low commodity prices. As a consequence, our future performance is subject to increased commodity price risks, and our future cash flows from operations may be subject to further declines if low commodity prices persist. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. We enter into derivative contracts only with counterparties that are creditworthy institutions and are deemed by management as competent and competitive market makers. We did not post collateral under any of these contracts as they are secured under our Credit Agreement or are uncollateralized trades. Please refer to Note 3 Derivative Financial Instruments in our Unaudited Condensed Consolidated Financial Statements included in this report for additional information.

We account for our derivative activities under the provisions of ASC Topic 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. Please refer to Note 3 Derivative Financial Instruments in our Unaudited Condensed Consolidated Financial Statements included in this report for additional information.

Interest Rate Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and the prime rate based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At September 30, 2016, the principal amount of our total long-term debt with a variable interest rate was $10.0 million and bears interest at rates further described in Note 7 Debt. Fluctuations in interest rates will cause our annual interest costs to fluctuate. At September 30, 2016, the interest rate on borrowings under our revolving credit facility was 2.772% per year. If these borrowings at September 30, 2016 were to remain constant, a 10% change in interest rates would impact our cash flow by approximately $28,000 per year.

Disclosure of Limitations

Because the information above included only those exposures that existed at September 30, 2016, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is accurately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information 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. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily applied its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As of September 30, 2016, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Accounting Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)). Based on that evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that, as of September 30, 2016 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 that occurred during the quarter ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, 2016, 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, 2015.

Item 1A. Risk Factors

There have been no material changes during the period ended September 30, 2016 in our “Risk Factors” as discussed in Item 1A to our Annual Report on Form 10-K for the year ended December 31, 2015.

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 5. Other Information

None.

Item 6. Exhibits

Incorporated by Reference

Exhibit No.

Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

31.1

Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

31.2

Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

32.1

Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act

32.2

Certification of the Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act

101.INS

XBRL Instance Document

101.SCH

XBRL Schema Document

101.CAL

XBRL Calculation Linkbase Document

101.DEF

XBRL Definition Linkbase Document

101.LAB

XBRL Label Linkbase Document

101.PRE

XBRL Presentation Linkbase Document

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 8, 2016	Title:	President and Chief Executive Officer (Principal Executive Officer)

By:

/s/ G. Bret Wonson

Name:

G. Bret Wonson

Date: November 8, 2016

Title:

Principal Accounting Officer

(Principal Financial Officer)