este-10q_20160630.htm

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

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

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

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

As of August 4, 2016, 22,289,177 shares of common stock, $0.001 par value per share, were outstanding.

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:

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.

	June 30,			December 31,
ASSETS	2016			2015
Current assets:	(In thousands, except share amounts)
Cash and cash equivalents	$	18,870		$	23,264
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues		14,604			13,529
Joint interest billings and other		1,276			4,924
Prepaid expenses and other current assets		718			498
Current derivative asset		19			3,694
Total current assets		35,487			45,909
Oil and gas properties, successful efforts method:
Proved properties		340,086			283,644
Unproved properties		59,724			34,609
Total oil and gas properties		399,810			318,253

Accumulated depreciation, depletion, and amortization		(130,776	)		(119,920	)
Net oil and gas properties		269,034			198,333
Other noncurrent assets:
Goodwill		20,568			17,532
Office and other equipment, less accumulated depreciation of $1,315 and $1,028 at June 30, 2016 and December 31, 2015		1,705			1,934
Other noncurrent assets		1,183			1,236
TOTAL ASSETS	$	327,977		$	264,944
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	10,493		$	11,580
Accrued expenses		9,266			12,975
Revenues and royalties payable		7,795			8,576
Current porting of long-term debt		1,554			—
Current derivative liability		1,463			—
Advances		655			15,447
Total current liabilities		31,226			48,578

Noncurrent liabilities:
Long-term debt		13,505			11,191
Asset retirement obligations		5,597			5,075
Noncurrent derivative liability		1,122			—
Deferred tax liability		664
Other noncurrent liabilities		198			227
Total noncurrent liabilities		21,086			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 June 30, 2016 and December 31, 2015		23			14
Additional paid-in capital		451,462			358,086
Accumulated deficit		(175,360	)		(157,767	)
Treasury stock, 15,357 shares at June 30, 2016 and December 31, 2015		(460	)		(460	)
Total equity		275,665			199,873

TOTAL LIABILITIES AND EQUITY	$	327,977		$	264,944

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
REVENUES	(In thousands, except share and per share amounts)
Oil, natural gas, and natural gas liquids revenues:
Oil	$	8,097		$	12,163		$	13,636		$	21,201
Natural gas		1,016			1,982			1,959			3,512
Natural gas liquids		664			813			992			1,487
Total oil, natural gas, and natural gas liquids revenues		9,777			14,958			16,587			26,200
Gathering income		33			95			87			173
Gain on sales of oil and gas properties, net		—			1,680			—			1,680
Total revenues		9,810			16,733			16,674			28,053
OPERATING COSTS AND EXPENSES
Production costs:
Lease operating expense		3,201			4,239			6,267			8,613
Severance taxes		514			746			896			1,376
Rig idle and contract termination expense		3,790			—			5,059			—
Depreciation, depletion, and amortization		5,598			8,674			11,103			14,598
Re-engineering and workovers		306			167			581			286
Exploration expense		—			142			5			142
General and administrative expense		2,273			2,484			5,471			5,055
General and administrative expense - stock-based compensation		561			—			561			—
Total operating costs and expenses		16,243			16,452			29,943			30,070
(Loss) income from operations		(6,433	)		281			(13,269	)		(2,017	)
OTHER INCOME (EXPENSE)
Interest expense, net		(370	)		(169	)		(593	)		(338	)
Net loss on derivative contracts		(4,228	)		(1,318	)		(3,463	)		(644	)
Other income (expense), net		45			163			(82	)		257
Total other income (expense)		(4,553	)		(1,324	)		(4,138	)		(725	)
Loss before income taxes		(10,986	)		(1,043	)		(17,407	)		(2,742	)
Income tax expense (benefit)		186			(295	)		186			(880	)
Net loss	$	(11,172	)	$	(748	)	$	(17,593	)	$	(1,862	)
Net loss per common share:
Basic	$	(0.69	)	$	(0.05	)	$	(1.17	)	$	(0.13	)
Diluted	$	(0.69	)	$	(0.05	)	$	(1.17	)	$	(0.13	)
Weighted average common shares outstanding:
Basic		16,121,568			13,835,128			14,978,348			13,835,128
Diluted		16,121,568			13,835,128			14,978,348			13,835,128

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

					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		—		—		561		—			—			—			561
Shares issued in Lynden Arrangement		3,700,279		4		45,695		—			—			—			45,699
Net loss		—		—		—		(17,593	)		—			—			(17,593	)
At June 30, 2016		22,289,177	$	23	$	451,462	$	(175,360	)		(15,357	)	$	(460	)	$	275,665

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

	Six Months Ended June 30,
	2016			2015
Cash flows from operating activities:	(In thousands)
Net loss	$	(17,593	)	$	(1,862	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, and amortization		11,103			14,598
Unrealized loss on derivative contracts		6,260			3,081
Rig idle and termination expense		5,059			—
Accretion of asset retirement obligations		261			282
Stock-based compensation		561			—
Deferred income taxes		—			(871	)
Amortization of deferred financing costs		142			130
Settlement of asset retirement obligations		—			(46	)
Gain on sale of assets		—			(1,680	)
Changes in assets and liabilities:
Decrease in accounts receivable		4,414			4,397
(Increase) decrease in prepaid expenses and other		(132	)		427
Decrease in accounts payable and accrued expenses		(6,634	)		(18,356	)
Decrease in revenue and royalties payable		(780	)		(2,895	)
Decrease in advances		(14,792	)		(7,566	)
Net cash used in operating activities		(12,131	)		(10,361	)
Cash flows from investing activities:
Lynden Arrangement, net of cash acquired		(31,334	)		—
Acquisitions of oil and gas property		—			(5,430	)
Additions to oil and gas property and equipment		(6,749	)		(42,888	)
Additions to other property and equipment		(44	)		(279	)
Proceeds from sales of oil and gas properties		—			3,506
Net cash used in investing activities		(38,127	)		(45,091	)
Cash flows from financing activities:
Proceeds from borrowings		36,597			—
Repayment of borrowings		(37,788	)		—
Issuance of common stock, net of offering costs of $2.7 million		47,125			—
Deferred financing costs		(70	)		(125	)
Net cash provided by (used in) financing activities		45,864			(125	)
Net decrease in cash and cash equivalents		(4,394	)		(55,577	)
Cash and cash equivalents at beginning of period		23,264			100,447
Cash and cash equivalents at end of period	$	18,870		$	44,870
Supplemental disclosure of cash flow information
Cash paid for:
Interest	$	416		$	175
Non-cash investing and financing activities:
Common stock issued for Lynden Arrangement	$	45,698		$	—
Asset retirement obligations	$	94		$	91

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

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.

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.

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.

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. 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. 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.

In May 2016, the Company 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. 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 Topic ASC 805, Business Combinations, which among 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 financial statements were prepared. Additional changes to the purchase price allocation may results 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):

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 Lynden and the Company 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).

Beginning at the Effective Time, for both the three and six months ended June 30, 2016, the Company recognized $1.4 million of oil, natural gas and natural gas liquids sales related to the Lynden assets and $1.0 million of operating expenses, inclusive of depletion. During the three and six months ended June 30, 2016, the Company recognized $0.3 million and $0.7 million, respectively, of non-recurring transaction costs related to this acquisition.

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):

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.

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.

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.

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 “Net loss on derivative contracts” 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.

The Company had the following open crude oil and natural gas derivative contracts as of June 30, 2016:

Period	Instrument	Commodity	Volume in MMBtu / Bbls		Fixed Price
July 2016 - December 2018	Swap	Crude Oil		150,000	$	51.45
January 2017 - December 2017	Swap	Crude Oil		120,000	$	46.75
July 2016 - December 2016	Swap	Crude Oil		60,000	$	45.17
January 2018 - December 2018	Swap	Crude Oil		60,000	$	50.10
July 2016 - December 2016	Swap	Crude Oil		60,000	$	48.10
January 2017 - December 2017	Swap	Crude Oil		60,000	$	49.30
July 2016 - March 2017	Swap	Crude Oil		45,000	$	42.30
July 2016 - March 2017	Swap	Crude Oil		45,000	$	42.30
July 2016 - December 2016	Swap	Crude Oil		30,000	$	60.80
July 2016 - December 2016	Swap	Crude Oil		30,000	$	60.80
January 2017 - December 2017	Swap	Natural Gas		480,000	$	2.785
July 2016 - December 2016	Swap	Natural Gas		420,000	$	2.530
July 2016 - December 2017	Swap	Natural Gas		360,000	$	2.975
January 2017 - December 2017	Swap	Natural Gas		240,000	$	2.860
July 2016 - December 2016	Swap	Natural Gas		60,000	$	2.380

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):

		June 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	$	629		$	(610	)	$	19		$	3,694	$	—	$	3,694
Commodity contracts	Current derivative liabilities	$	(2,073	)	$	610		$	(1,463	)	$	—	$	—	$	—
Commodity contracts	Noncurrent derivative liabilities	$	(1,122	)	$	—		$	(1,122	)	$	—	$	—	$	—

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):

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

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

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

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

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

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the six months ended June 30, 2016.

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):

June 30, 2016	Level 1		Level 2			Level 3		Total
Financial assets
Current derivative assets	$	—	$	19		$	—	$	19
Total financial assets	$	—	$	19		$	—	$	19

Financial liabilities
Current derivative liabilities	$	—	$	(1,463	)	$	—	$	(1,463	)
Noncurrent derivative liabilities		—		(1,122	)		—		(1,122	)
Total financial liabilities	$	—	$	(2,585	)	$	—	$	(2,585	)

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

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation on its credit facility has a floating interest rate structure, therefore its carrying amounts approximates its fair value.

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 six months ended June 30, 2016 or 2015.

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 underwriter’s 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.

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Basic EPS:
Net loss	$	(11,172	)	$	(748	)	$	(17,593	)	$	(1,862	)

Weighted average common shares outstanding		16,121,568			13,835,128			14,978,348			13,835,128

Basic loss per common share	$	(0.69	)	$	(0.05	)	$	(1.17	)	$	(0.13	)

Diluted EPS:
Net loss	$	(11,172	)	$	(748	)	$	(17,593	)	$	(1,862	)

Weighted average common shares outstanding		16,121,568			13,835,128			14,978,348			13,835,128
Add: Dilutive effect of restricted stock units		—			—			—			—
Diluted weighted average common shares outstanding		16,121,568			13,835,128			14,978,348			13,835,128

Diluted loss per common share	$	(0.69	)	$	(0.05	)	$	(1.17	)	$	(0.13	)

For the three and six months ended June 30, 2016, the Company excluded 37,334 and 18,480 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 six months ended June 30, 2015, there were no restricted stock units issued or outstanding under the Company’s long-term incentive plan.

In December 2014, our 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 our 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 June 30, 2016 727,500 shares of common stock remained available for issuance under the 2014 Plan.

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 (“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 six months ended June 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 June 30, 2016, all 772,500 RSUs were unvested.

For both the three and six months ended June 30, 2016, the Company recognized $0.6 million of stock-based compensation expense. There was no stock-based compensation expense recognized for the comparable periods in 2015. At June 30, 2016, the Company had $9.1 million of unrecognized compensation expense related to unvested RSUs to be recognized over a weighted-average period of 1.5 years.

In December 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility. At June 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 June 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 June 30, 2016, the Company had a $75.0 million borrowing base, with $10.0 million of debt outstanding, (bearing an interest rate of 2.715%), $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 asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period. As of June 30, 2016 and December 31, 2015, the Company was in compliance with these covenants under the credit facility.

Interest expense for the three and six months ended June 30, 2016, includes amortization of deferred financing costs of $72,000 and $0.1, million, respectively. Interest expense for the three and six months ended June 30, 2015, includes amortization of deferred financing costs of $65,000 and $0.1, million, respectively. As of June 30, 2016 and December 31, 2015, $0.8 million 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.

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 30, 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 the effective interest method of approximately 9.1% over the life of the note. As of June 30, 2016, the Company recorded $1.6 million as a current liability and $3.5 million as a long-term liability relating to the note.

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 June 30, 2016 (in thousands):

For both the three and six months ended June 30, 2016, the Company recorded $0.2 million of income tax expense related to its 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”). 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 six month ended June 30, 2016 for the Lynden subsidiaries was 34.5%, which included approximately 0.5% for the estimated portion of the subsidiaries 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 six months ended June 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 and six months ended June 30, 2015, the Company recorded an income tax benefit of $0.3 million and $0.9 million, respectively, all of which was deferred. The effective tax rate for the three and six month ended June 30, 2015 was 28% and 32%, respectively, which included approximately 0.7% of the estimated portion of the Company’s income subject to income tax in the states in which the Company operates.

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.

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.

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 June 30, 2016, the Company’s share of the remaining commitment on this contract is approximately $4.1 million.

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.

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 recently 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.

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.”

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, it was our intent to limit our operations. We temporarily suspended drilling and completion operations within our operated assets during the first half of 2016 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. Our actions are in direct response to continuing low commodity prices. While we believe we have made appropriate adjustments, we have also maintained a positive corporate culture and retained an outstanding staff. If commodity prices improve and stabilize during the second half of 2016, then we may increase certain drilling and completion activities. The following is a brief outline of our current plans:

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 first six months of 2016 decreased 31% for crude oil, 30% for natural gas and 23% 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 six 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 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.

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.

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.

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

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 June 30, 2016 and 2015, are presented below:

	Three Months Ended June 30,
	2016		2015		Change
Sales volumes:
Oil (MBbl)		201		230		(29	)
Natural gas (MMcf)		545		739		(194	)
Natural gas liquids (MBbl)		50		58		(8	)
Barrels of oil equivalent (MBOE) ⁽¹⁾		343		411		(68	)
Barrels of oil equivalent per day (BOEPD) ⁽¹⁾		3,759		4,517		(758	)

Average prices realized: ⁽²⁾
Oil (Bbl)	$	40.28	$	52.94	$	(12.66	)
Natural gas (Mcf)	$	1.87	$	2.68	$	(0.81	)
Natural gas liquids (Bbl)	$	13.18	$	14.01	$	(0.83	)

	Three Months Ended June 30,
(In thousands)	2016		2015		Change
Oil, natural gas, and natural gas liquids revenues:
Oil	$	8,097	$	12,163	$	(4,066	)
Natural gas		1,016		1,982		(966	)
Natural gas liquids		664		813		(149	)
Other operating revenues:
Gathering income		33		95		(62	)
Gain on sales of oil and gas properties, net		—		1,680		(1,680	)
Total revenues	$	9,810	$	16,733	$	(6,923	)

As noted above, the Arrangement closed in May 2016. The revenue and expenses of the Midland Basin properties acquired in the Arrangement were included in our results from May 18, 2016, the closing date of the transaction, through June 30, 2016.

For the three months ended June 30, 2016, oil revenues decreased by $4.1 million or 33% relative to the comparable period in 2015. Of the decrease, $2.9 million was attributable to the decline in our realized price and $1.2 million was attributable to decreased volume. Our average realized price per Bbl decreased from $52.94 to $40.28 or 24%. We had a net decrease in the volume of oil sold of 29 MBbls. The Midland Basin properties we acquired in the Arrangement provided an additional 25 MBbls, however our operated Eagle Ford, which includes newer wells in their initial steeper decline rate, decreased by 47 MBbls. The remaining 7 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.

For the three months ended June 30, 2016, natural gas revenues decreased by $1.0 million or 49% relative to the comparable period in 2015. Of the decrease, $0.6 million was attributable to the decline in our realized price and $0.4 million was attributable to decreased volumes. Our average realized price per Mcf decreased from $2.68 to $1.87 or 30%. The volume of natural gas sold decreased by 195 MMcfs, our non-operated Eagle Ford property decreased by 200 MMcfs, our non-operated East Texas properties decreased by 46 MMcfs and our Oklahoma properties decreased by 16 MMcfs. The Midland Basin properties we acquired in the Arrangement partially offset these decreases and provided an additional 72 MMcfs. The remaining 5 MMcfs decrease was due to production declines and variability in sales volumes in our conventional properties mainly in Texas.

For the three months ended June 30, 2016, natural gas liquids revenues decreased by $0.1 million or 18% relative to the comparable period in 2015. The average realized price per Bbl decreased from $14.01 to $13.18 or 6%. The volume of natural gas liquids sold decreased by 8 MBbl or 14%. Our volumes sold decreased at both our operated and non-operated Eagle Ford properties and our non-operated assets in the Bakken-Three Forks area. These decreases were partially offset by 13 MBbl provided by the Midland Basin properties we acquired in the Arrangement.

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

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.

Total LOE decreased by $1.0 million or 25% for the three months ended June 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 three months ended June 30, 2016 by 10% or $0.93 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 for the three months ended June 30, 2016 decreased by $0.2 million or 31% 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 increased by 5% due to the mix of our production. During the three months ended June 30, 2016, a larger portion of a production and revenues where generated from oil wells, compared to wells which primarily produce natural gas, which do not qualify for full or partial severance tax exemptions. This increase caused our overall severance tax rate to increase over the comparable period during 2015.

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 $0.1 million during the three months ended June 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.

During the three months ended June 30, 2016, we incurred rig idle and contract termination expenses of $3.8 million related to the drilling rig we had under contract. 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 this contracted drilling rig. In connection with the termination, we issued a three-year amortizing promissory note with a principal amount of $5.1 million, which was equivalent to the unpaid idle charges and the termination fee.

G&A - primarily consist of employee remuneration, professional and consulting fees and other overhead expenses. G&A expenses decreased by $0.2 million from $2.5 million during the three months ended June 30, 2015 to $2.3 million during the three months ended June 30, 2016 primarily due to the salary and benefits reductions summarized in the Overview section above offset by professional fees related to the Arrangement of $0.3 million.

G&A – stock-based compensation includes the expense associated with the grant of restricted stock units (“RSUs”) issued to employees and non-employee directors. During the three months ended June 30, 2016 we recognized expense of $0.6 million related to the RSU grants that occurred on May 20, 2016 and June 1, 2016. The comparable prior period had no stock-based compensation expense since there were not any previously granted RSUs or other equity based compensation granted.

DD&A decreased for the three months ended June 30, 2016 by $3.1 million, or 35% relative to the comparable period during 2015 due to lower production volumes and reduced net book value in the 2016 period as a result of the significant impairments recognized as the end of 2015. On a per BOE basis, our overall DD&A rate, decreased by $4.74 or 22% from $21.10 during the three months ended June 30, 2015 to $16.36 during the three months ended June 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.

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense was $0.4 million for the three months ended June 30, 2016, as compared to $0.2 million for the three months ended June 30, 2015. During the 2016 period we had higher interest expense charges since we had a higher weighted average debt balance that was incurred in connection with the Arrangement.

During the three months ended June 30, 2016, we recorded a net loss on derivative contracts of $4.2 million, consisting of net gains on settlements of $0.8 million and unrealized mark-to-market losses of $5.0 million. During the three months ended June 30, 2016, we recorded net settlements related to crude oil contracts of $0.7 million and $0.1 million related to natural gas contracts. During the three months ended June 30, 2015, we recorded a net loss on derivative contracts of $1.3 million, consisting of net gains on settlements of $0.9 million and unrealized mark-to-market losses of $2.2 million. During the three months ended June 30, 2015, all of our net settlements related to crude oil contracts.

During the three months ended June 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 Lynden subsidiaries was 34.5% for the three months ended June 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 June 30, 2016 and other book to tax differences increased our net deferred tax asset but did not result in a recognized an 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 June 30, 2015 we recorded an income tax benefit of $0.3 million as a result of our pre-tax net loss.

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 six months ended June 30, 2016 and 2015, are presented below:

	Six Months Ended June 30,
	2016		2015		Change
Sales volumes:
Oil (MBbl)		406		438		(32	)
Natural gas (MMcf)		1,030		1,297		(267	)
Natural gas liquids (MBbl)		90		103		(13	)
Barrels of oil equivalent (MBOE) ⁽¹⁾		668		757		(89	)
Barrels of oil equivalent per day (BOEPD) ⁽¹⁾		3,668		4,185		(517	)

Average prices realized: ⁽²⁾
Oil (Bbl)	$	33.60	$	48.42	$	(14.82	)
Natural gas (Mcf)	$	1.90	$	2.71	$	(0.81	)
Natural gas liquids (Bbl)	$	11.01	$	14.38	$	(3.37	)

	Six Months Ended June 30,
(In thousands)	2016		2015		Change
Oil, natural gas, and natural gas liquids revenues:
Oil	$	13,636	$	21,201	$	(7,565	)
Natural gas		1,959		3,512		(1,553	)
Natural gas liquids		992		1,487		(495	)
Other operating revenues:
Gathering income		87		173		(86	)
Gain on sales of oil and gas properties, net		—		1,680		(1,680	)
Total revenues	$	16,674	$	28,053	$	(11,379	)

For the six months ended June 30, 2016, oil revenues decreased by $7.6 million or 36% relative to the comparable period in 2015. Of the decrease, $6.5 million was attributable to the decline in our realized price and $1.1 million was attributable to decreased volumes. Our average realized price per Bbl decreased from $48.42 to $33.60 or 31%. We had a net decrease in the volume of oil sold of 32 MBbls. The Midland Basin properties we acquired in the Arrangement provided an additional 25 MBbls and our non-operated Bakken-Three Forks property increased by 4 MBbls; these increases were offset by a 51 MBbls decrease from our operated Eagle Ford property, which includes newer wells in their initial steeper decline rate, and a 10 MBbls decrease from our non-operated Eagle Ford property.

For the six months ended June 30, 2016, natural gas revenues decreased by $1.6 million or 44% relative to the comparable period during 2015. Of the decrease, $1.1 million was attributable to the decline in our realized price and $0.5 million was attributable to decreased volumes. Our average realized price per Mcf decreased from $2.71 to $1.90 or 30%. The volume of natural gas sold decreased by 267 MMcfs; our non-operated Eagle Ford property decreased by 249 MMcfs, our non-operated East Texas properties decreased by 28 MMcfs and we sold 33 MMcfs less as a result of the sale of our Louisiana properties which was effective as of March 31, 2015. The Midland Basin properties we acquired in the Arrangement partially offset these decreases and provided an additional 72 MMcfs. The remaining 29 MMcfs decrease was due to production declines and variability in sales volumes in our conventional properties mainly in Texas.

For the six months ended June 30, 2016, natural gas liquids revenues decreased by $0.5 million or 33% relative to the comparable period during 2015. The average realized price per Bbl decreased from $14.38 to $11.01 or 23%. The volume of natural gas liquids sold decreased by 13 MBbl or 13%. Our volumes sold decreased at both our operated and non-operated Eagle Ford properties and our non-operated assets in our Bakken-Three Forks area. These decreases were partially offset by 13 MBbl provided by the Midland Basin properties we acquired in the Arrangement.

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

Total LOE decreased by $2.3 million or 27% for the six months ended June 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 six months ended June 30, 2016 by 19% or $2.01 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 for the six months ended June 30, 2016 decreased by $0.5 million or 35% 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 an increased by only 3% due to the mix of production and revenues.

Re-engineering and workover expenses increased by $0.3 million during the six months ended June 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.

We incurred rig idle and termination expenses of $5.1 million during the six months ended June 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, we issued a three-year amortizing promissory note with a principal amount of $5.1 million, which was equivalent to the unpaid idle charges and the termination fee.

G&A – expenses increased by $0.4 million from $5.1 million during the six months ended June 30, 2015 to $5.5 million during the six months ended June 30, 2016 primarily due to additional professional and consulting fees related to the Arrangement and the documenting and testing of controls as required by the Sarbanes-Oxley Act. The increase in professional and consulting fees was partially offset by the salary and benefits reductions summarized in the Overview section above. Included in G&A for the six months ended June 30, 2016 are professional fees related to the Arrangement of $0.7 million.

G&A – stock-based compensation includes the expense associated with the grant of RSUs issued to non-employee directors and employees. During the six months ended June 30, 2016 we recognized expense of $0.6 million related to the RSU grants that occurred on May 20, 2016 and June 1, 2016. The comparable prior period had no stock-based compensation expense since there were not any previously granted RSUs or other equity based compensation.

DD&A decreased for the six months ended June 30, 2016 by $3.5 million, or 24% relative to the comparable period during 2015 due to lower production volumes and reduced net book value in the 2016 period as a result of the significant impairments recognized during the three-month period ended December 31, 2015. On a per BOE basis, our overall DD&A rate, decreased by $2.64 or 14% from $19.27 during the six months ended June 30, 2015 to $16.63 during the six months ended June 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.

Interest expense for the six months ended June 30, 2016 was $0.6 million compared to $0.3 million for the comparable period during 2015. During the 2016 period we had higher interest expense charges since we had a higher weighted average debt balance due to the Arrangement and higher amortization of deferred financing costs.

During the six months ended June 30, 2016, we recorded a net loss on derivative contracts of $3.5 million, consisting of net gains on settlements of $2.8 million and unrealized mark-to-market losses of $6.3 million. During the six months ended June 30, 2016, we recorded net settlements related to crude oil contracts of $2.6 million and $0.2 million related to natural gas contracts. During the six months ended June 30, 2015, we recorded a net loss on derivative contracts of $0.6 million, consisting of net gains on settlements of $2.4 million and unrealized mark-to-market losses of $3.0 million. During the six months ended June 30, 2015, we recorded net settlements related to crude oil contracts of $2.2 million and $0.2 million related to natural gas contracts.

During the six months ended June 30, 2016, we recorded $0.2 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 the Lynden subsidiaries was 34.5% for the three months ended June 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 six months ended June 30, 2016 and other book to tax differences increased our net deferred tax asset but did not result in a recognized an 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 six months ended June 30, 2015 we recorded an income tax benefit of $0.9 million as a result of our pre-tax net loss.

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.

In June 2016, we completed a public offering of 4,753,770 shares of common stock (including 253,770 shares purchased pursuant to the underwriter’s 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.

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 June 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 June 30, 2016.

In connection with the termination of a drilling rig contract, we entered into a $5.1 million three-year promissory note 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 principle balance on the note is 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 was reflected in our Condensed Consolidated Statement of Operations during the three and six months ended June 30, 2016, and the note was included in our Condensed Consolidated Balance Sheet as of June 30, 2016.

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 used by operating activities for the six months ended June 30, 2016 were $12.1 million compared to $10.4 million for the six months ended June 30, 2015. The net loss, after adjustments for non-cash items, provided cash of $6.0 million for the six months ended June 30, 2016 compared to $13.6 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 six months ended June 30, 2016 was $17.9 million compared to $24.0 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 low 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.

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 held by Lynden of $5.3 million. Cash applied to oil and natural gas properties for the six months ended June 30, 2016 and 2015 was $6.7 million and $42.9 million, respectively. Cash applied to other non-oil and gas property fixed assets for the six months ended June 30, 2016 and 2015 was $44,000 and $0.3 million, respectively. 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.

During the six months ended June 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 six months ended June 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.

We had no significant financing activities for the six months ended June 30, 2015.

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 $2.6 million at June 30, 2016. Based on the published commodity futures price curves for the underlying commodity as of June 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 $2.4 million to a net liability of $5.0 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 $3.8 million to a net asset of $1.2 million. There would also be a similar increase or decrease in “Net gain on derivative contracts” in the Unaudited Condensed Consolidated Statements of Operations.

In conjunction with our office lease located in The Woodlands, Texas, we established a letter of credit in the amount of $0.2 million and $0.3 million at June 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.

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.

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 its 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.

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.

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.

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.

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 June 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 June 30, 2016, the interest rate on borrowings under our revolving credit facility was 2.715% per year. If these borrowings at June 30, 2016 were to remain constant, a 10% change in interest rates would impact our cash flow by approximately $27,000 per year.

Because the information above included only those exposures that existed at June 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.

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 June 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 June 30, 2016 our disclosure controls and procedures were effective.

During the quarter ended June 30, 2016, there were changes to the Company’s internal control over financial reporting as described below:

Material weakness related to inadequate segregation of duties. As of December 31, 2015 management concluded that it had certain design deficiencies relating to the segregation of duties, review and approval and verification procedures, primarily resulting from our limited number of accounting staff, during a continuing industry-wide downturn, available to perform such procedures. Additionally, management identified certain design deficiencies related access over information systems. During 2016, the Company implemented the following measures to address this previously reported material weakness:

Management concluded that the above control enhancements successfully remediated the material weakness related to segregation of duties during the second quarter of 2016.

There were no additional changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

From time to time, we may be involved in various legal proceedings and claims in the ordinary course of business. As of June 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.

There have been no material changes during the period ended June 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.

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

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.

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

Large accelerated filer	o	Accelerated filer	þ

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

		Page

	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)	5
	Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	5
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015	6
	Condensed Consolidated Statements of Equity for the Six Months Ended June 30, 2016	7
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 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	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33

	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

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		1,837
Deferred tax liability⁽¹⁾		664
Asset retirement obligations		167
Total consideration plus liabilities assumed	$	84,963
Fair Value of Assets Acquired:
Cash and cash equivalents ⁽⁴⁾	$	5,263
Current assets		1,948
Proved oil and gas properties ⁽²⁾⁽³⁾		48,116
Unproved oil and gas properties		26,600
Amount attributable to assets acquired	$	81,927
Goodwill ⁽⁵⁾	$	3,036

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
	(Unaudited)
Revenue	$	12,737		$	21,299	$	22,084		$	36,319
(Loss) income before taxes	$	(10,190	)	$	415	$	(16,904	)	$	(1,556	)
Net (loss) income available to Earthstone common stockholders	$	(10,847	)	$	207	$	(17,796	)	$	(1,085	)
Pro Forma net (loss) income per common share:
Basic and diluted	$	(0.62	)	$	0.01	$	(1.01	)	$	(0.06	)

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

		Three Months Ended June 30,						Six Months Ended June 30,
Derivatives not designated as hedging contracts under ASC Topic 815	Statement of Operations Location	2016			2015			2016			2015
Unrealized loss on commodity contracts	Net loss on derivative contracts	$	(5,034	)	$	(2,261	)	$	(6,260	)	$	(3,081	)
Realized gain on commodity contracts	Net loss on derivative contracts	$	806		$	943		$	2,797		$	2,437
		$	(4,228	)	$	(1,318	)	$	(3,463	)	$	(644	)

	2016
Asset retirement obligations at December 31, 2015	$	5,075
Liabilities incurred		106
Accretion expense		261
Acquisitions		167
Revision of estimates		(12	)
Asset retirement obligations at June 30, 2016	$	5,597

	EARTHSTONE ENERGY, INC.

	By:	/s/ Frank A. Lodzinski
	Name:	Frank A. Lodzinski
Date: August 9, 2016	Title:	President and Chief Executive Officer (Principal Executive Officer)