Delaware		~~84-0592823~~
(State of Incorporation or Organization)		84-0592823 (I.R.S. Employer Identification No.)

633 17th Street, Suite ~~1900,~~2320, Denver, Colorado		~~80202-3619~~
(Address of principal executive office)		80202-3619 (Zip Code)

(303) 296-3076

(Registrant’s telephone number, including area code)

~~(Registrant’s telephone number, including area code)~~

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Check whether the issuer is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

Shares of common stock outstanding on ~~February 8,~~August 12, 2013: ~~1,720,712~~1,732,250

EARTHSTONE ENERGY, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements		4

	Condensed Consolidated Balance Sheets:
	~~December 31, 2012~~June 30, 2013 (Unaudited) and March 31, ~~2012~~2013		4	5

	Condensed Consolidated Statements of Operations:
	Three Months Ended June 30, 2013 and ~~Nine Months Ended December 31,~~ 2012 ~~and 2011(Unaudited)~~(Unaudited)		6	7

	Condensed Consolidated Statements of Cash Flows:
	~~Nine~~Three Months Ended ~~December 31,~~June 30, 2013 and 2012 ~~and 2011~~ (Unaudited)		7	8

	Notes to Unaudited Condensed Consolidated Financial Statements:
	~~December 31, 2012~~June 30, 2013		8	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		12	13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		20	19

Item 4.	Controls and Procedures		20	19


PART II. OTHER INFORMATION


Item 1.	Legal Proceedings		21	20

Item 1A.	Risk Factors		21	20

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		21	20

Item 3.	Defaults Upon Senior Securities		22	20

Item 4.	Mine Safety Disclosures		22	20

Item 5.	Other Information		22	20

Item 6.	Exhibits		22	21


Signatures			23	22

FORWARD-LOOKING STATEMENTS

This Current Report on Form 10-Q, including information incorporated herein by reference, contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs, assumptions and information currently available to management. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "predict," "plan," "should," "likely," "may," "will," "continue" or similar expressions are intended to identify such statements. All statements other than statements of historical facts that address activities that we anticipate will or may occur in the future are forward-looking statements. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty. Forward-looking statements relate to, among other things:

●	our strategies, either existing or anticipated;

●	our future financial position, including anticipated liquidity;

●	our ability to satisfy obligations from cash generated from operations;

●	amounts and nature of future capital expenditures, including future share repurchases;

●	acquisitions and other business opportunities;

●	operating costs and other expenses, including asset retirement obligation expenses;

●	wells expected to be drilled, other anticipated exploration efforts and associated expenses;

●	estimates of proved oil and natural gas reserves, deferred tax assets, and depletion rates;

●	our ability to meet additional acreage, seismic and/or drilling cost requirements;

●	other estimates and assumptions we use in our accounting policies.

Factors that could cause actual results to differ materially from our expectations include, among others, such things as:

●	loss of senior management or technical personnel;

●	oil and natural gas prices and production costs;

●	our ability to replace oil and natural gas reserves, including changes in reserve estimates resulting from expected oil and gas prices, production rates, tax rates and production costs;

●

~~Our~~our ability to remain in compliance with the financial covenants related to our Credit Facility may be affected by events beyond our control, including market prices for our oil and gas. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect our liquidity by rendering us unable to borrow further under the Credit Facility.

●	exploitation, development, production and exploration results, including mechanical failure;

●	the estimated costs of asset retirement obligations, including whether or not those retirement costs, in whole or in part, are ever actually incurred in the future;

●	the potential unavailability of drilling rigs and other field equipment and services;

●	the existence of unanticipated liabilities relating to existing properties or those acquired in the future, including environmental liabilities;

●	factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment;

●	the willingness and ability of third parties to honor their contractual commitments;

●	permitting issues;

●	the nature, extent and duration of workovers;

●	the impact and costs related to compliance with or changes in laws governing our operations;

●	acquisitions and other business opportunities (or the lack thereof) that may be pursued by us;

●	competition for properties and the effect of such competition on the price of those properties;

●	economic, market or business conditions, including any change in interest rates or inflation;

●	the lack of available capital and financing;

●	risk factors consistent with comparable companies within our industry, especially companies with similar market capitalization and/or employee census; and

●	weather and other factors, many of which are beyond our control.

Furthermore, forward-looking statements are made based on our current assessment available at the time. Subsequently obtained information concerning the merits of any property, as well as changes in estimated exploration and development costs and ownership interest, may result in revisions to our expectations and intentions and, thus, we may alter our plans regarding any exploration and development activities.

Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. As with comparable companies within our industry, there are numerous factors that could cause actual results to differ materially from our expectations. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

PART I – FINANCIAL INFORMATION

~~ITEM~~Item 1. ~~FINANCIAL STATEMENTS~~

~~Earthstone Energy, Inc.~~

~~Condensed Consolidated Balance Sheets~~

~~Page 1 of 2~~

December 31, March 31,
2012 2012
(Unaudited)
ASSETS
Current assets:
     Cash and cash equivalents $ 2,157,000 $ 6,778,000
     Accounts receivable:
          Oil and gas sales 2,988,000 2,389,000
          Joint interest and other receivables
                 net of allowance of ($38,000) and ($60,000), respectively 195,000 90,000
     Other current assets 785,000 749,000

Total current assets 6,125,000 10,006,000

Oil and gas properties, full cost method:
     Proved properties 48,166,000 37,112,000
     Unproved properties 2,908,000 4,409,000
     Accumulated depletion and impairment (27,062,000 ) (25,778,000 )

Net oil and gas properties 24,012,000 15,743,000

Support equipment and other non-current assets
      net of accumulated depreciation of ($402,000) and ($383,000), respectively 529,000 457,000

Total non-current assets 24,541,000 16,200,000

Total assets $ 30,666,000 $ 26,206,000

~~See accompanying Notes to Unaudited Condensed Consolidated~~ Financial Statements

Earthstone Energy, Inc.

4Condensed Consolidated Balance Sheets

Page 1 of 2

~~Earthstone Energy, Inc.~~

~~Condensed Consolidated Balance Sheets~~

~~Page 2 of 2~~

December 31, March 31,
2012 2012
(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
     Accounts payable $ 1,280,000 $ 824,000
     Accrued liabilities 3,199,000 2,610,000

Total current liabilities 4,479,000 3,434,000

Long-term liabilities:
     Long term debt 2,000,000 -
     Deferred tax liability 2,892,000 2,731,000
     Asset retirement obligation, less current portion 1,688,000 1,693,000

Total long-term liabilities 6,580,000 4,424,000

Total liabilities 11,059,000 7,858,000

Shareholders’ Equity:
     Preferred shares, $0.001 par value, 600,000 authorized - -
          and none issued or outstanding
     Common shares, $0.001 par value, 6,400,000 shares authorized and 18,000 18,000
          1,802,000 and 1,788,000 shares issued, respectively
     Additional paid-in capital 23,241,000 23,108,000
     Treasury stock, at cost, 82,000 shares (457,000 ) (457,000 )
     Accumulated deficit (3,195,000 ) (4,321,000 )

Total shareholders’ equity 19,607,000 18,348,000

Total liabilities and shareholders’ equity $ 30,666,000 $ 26,206,000

	June 30,			March 31,
	2013			2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,202,000		$	2,180,000
Accounts receivable:
Oil and gas sales		2,833,000			3,055,000
Joint interest and other receivables
net of allowance of ($38,000) at June 30, 2013 and March 31, 2013		131,000			328,000
Other current assets		780,000			814,000

Total current assets		5,946,000			6,377,000

Oil and gas properties, full cost method:
Proved properties		58,374,000			53,265,000
Unproved properties		1,687,000			2,156,000
Accumulated depletion and impairment		(28,488,000	)		(27,729,000	)

Net oil and gas properties		31,573,000			27,692,000

Support equipment and other non-current assets
net of accumulated depreciation of ($442,000) and ($416,000), respectively		729,000			611,000

Total non-current assets		32,302,000			28,303,000

Total assets	$	38,248,000		$	34,680,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

~~Earthstone Energy, Inc.~~

~~Condensed Consolidated Statements of Operations~~

~~(Unaudited)~~

Three Months Ended Nine Months Ended
December 31, December 31,
2012 2011 2012 2011
Revenues:
     Oil and gas sales $ 2,752,000 $ 3,830,000 $ 7,672,000 $ 8,815,000
     Well service and water-disposal revenue 82,000 36,000 318,000 121,000

Total revenues 2,834,000 3,866,000 7,990,000 8,936,000

Expenses:
     Oil and gas production 866,000 983,000 2,523,000 2,610,000
     Production tax 239,000 350,000 697,000 688,000
     Well service and water-disposal 18,000 - 60,000 -
     Depletion and depreciation 577,000 363,000 1,332,000 788,000
     Accretion of asset retirement obligation 43,000 43,000 130,000 125,000
     General and administrative 669,000 473,000 1,977,000 1,422,000

Total expenses 2,412,000 2,212,000 6,719,000 5,633,000

Income from operations 422,000 1,654,000 1,271,000 3,303,000

Other income (expense):
     Interest and other income 51,000 1,000 59,000 68,000
     Interest and other expenses (2,000 ) - (3,000 ) (3,000 )

Total other income 49,000 1,000 56,000 65,000

Income before income tax 471,000 1,655,000 1,327,000 3,368,000

Current income tax expense 14,000 34,000 40,000 129,000
Deferred income tax expense
87,000 469,000 161,000 694,000

Total income tax expense 101,000 503,000 201,000 823,000

Net income $ 370,000 $ 1,152,000 $ 1,126,000 $ 2,545,000

Per share amounts:
     Basic $ 0.22 $ 0.68 $ 0.65 $ 1.49
     Diluted $ 0.22 $ 0.68 $ 0.65 $ 1.49

Weighted average common shares outstanding:
     Basic 1,720,712 1,706,588 1,720,712 1,710,035
     Diluted 1,720,712 1,706,588 1,720,712 1,710,035
Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

Page 2 of 2

	June 30,			March 31,
	2013			2013
	(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	2,099,000		$	1,631,000
Accrued liabilities		5,129,000			3,971,000

Total current liabilities		7,228,000			5,602,000

Long-term liabilities:
Long-term debt		5,000,000			4,000,000
Deferred tax liability		3,110,000			2,971,000
Asset retirement obligation, less current portion		1,872,000			1,809,000

Total long-term liabilities		9,982,000			8,780,000

Total liabilities		17,210,000			14,382,000

Shareholders’ equity:
Preferred shares, $0.001 par value, 600,000 authorized		-			-
and none issued or outstanding
Common shares, $0.001 par value, 6,400,000 shares authorized and		18,000			18,000
1,814,000 and 1,802,000 shares issued, respectively
Additional paid-in capital		23,325,000			23,278,000
Treasury stock, at cost, 82,000 shares		(457,000	)		(457,000	)
Accumulated deficit		(1,848,000	)		(2,541,000	)

Total shareholders’ equity		21,038,000			20,298,000

Total liabilities and shareholders’ equity	$	38,248,000		$	34,680,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

~~Earthstone Energy, Inc.~~

~~Condensed Consolidated Statements of Cash Flows~~

~~(Unaudited)~~

Nine Months Ended
December 31,
2012 2011
Cash flows from operating activities:
     Net income $ 1,126,000 $ 2,545,000
     Adjustments to reconcile net income to net cash provided by operating activities:

           Depletion and depreciation 1,332,000 788,000
           Deferred income tax expense 161,000 694,000
           Accretion of asset retirement obligation 130,000 125,000
           Share-based compensation 133,000 66,000
     Change in:
           Accounts receivable, net (704,000 ) (938,000 )
           Other current assets (148,000 ) 62,000
           Accounts payable, accrued and other liabilities (48,000 ) (258,000 )

Net cash provided by operating activities 1,982,000 3,084,000

Cash flows from investing activities:
     Oil and gas properties (8,483,000 ) (4,663,000 )
     Purchases of support equipment and other non-current assets (90,000 ) (96,000 )

Net cash (used in) investing activities (8,573,000 ) (4,759,000 )

Cash flows from financing activities:
     Borrowings on long term debt 2,000,000 -
     Deferred financing fees (30,000 ) -
     Purchase of treasury shares - (84,000 )

Net cash provided by (used in) financing activities 1,970,000 (84,000 )

Cash and cash equivalents:
Net decrease in cash and cash equivalents (4,621,000 ) (1,759,000 )
Cash and cash equivalents, beginning of year 6,778,000 4,051,000

Cash and cash equivalents, end of period $ 2,157,000 $ 2,292,000

Supplemental disclosure of cash flow information:
     Cash paid for interest $ 3,000 $ -
     Cash paid for income tax $ 341,000 $ 1,000
Non-cash:
    Increase in oil and gas property due to asset retirement obligation $ 35,000 $ 10,000
     Accrued capital expenditures $ 923,000 $ 957,000
     Prepaid capital expenditures $ 112,000 $ 46,000

	Three Months Ended
	June 30,
	2013			2012
Revenues:
Oil and gas sales	$	3,582,000		$	2,220,000
Well service and water-disposal revenue		13,000			127,000

Total revenues		3,595,000			2,347,000

Expenses:
Oil and gas production		835,000			834,000
Production tax		309,000			196,000
Well service and water-disposal		37,000			23,000
Depletion and depreciation		786,000			294,000
Accretion of asset retirement obligation		49,000			43,000
General and administrative		693,000			681,000

Total expenses		2,709,000			2,071,000

Income from operations		886,000			276,000

Other income (expense):
Interest and other income		8,000			2,000
Interest and other expenses		(33,000	)		-

Total other income (expense)		(25,000	)		2,000

Income before income tax		861,000			278,000

Current income tax expense		27,000			12,000
Deferred income tax expense (benefit)		141,000			(4,000	)

Total income tax expense		168,000			8,000

Net income	$	693,000		$	270,000

Per share amounts:
Basic	$	0.40		$	0.16
Diluted	$	0.40		$	0.16

Weighted average common shares outstanding:
Basic		1,732,250			1,720,712
Diluted		1,732,250			1,720,712

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Earthstone Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	693,000		$	270,000
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion and depreciation		786,000			294,000
Deferred income tax expense		141,000			(4,000	)
Accretion of asset retirement obligation		49,000			43,000
Share-based compensation		47,000			60,000
Amortization of deferred financing costs		3,000			-
Change in:
Accounts receivable, net		419,000			441,000
Other current assets		34,000			(772,000	)
Accounts payable, accrued and other liabilities		716,000			(374,000	)

Net cash provided by (used in) operating activities		2,888,000			(42,000	)

Cash flows from investing activities:
Oil and gas properties		(3,718,000	)		(2,122,000	)
Purchases of support equipment and other non-current assets		(144,000	)		(28,000	)

Net cash used in investing activities		(3,862,000	)		(2,150,000	)

Cash flows from financing activities:
Borrowings on long-term debt		1,000,000			-
Deferred financing fees		(4,000	)		-

Net cash provided by financing activities		996,000			-

Cash and cash equivalents:
Net increase (decrease) in cash and cash equivalents		22,000			(2,192,000	)
Cash and cash equivalents, beginning of year		2,180,000			6,778,000

Cash and cash equivalents, end of period	$	2,202,000		$	4,586,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	31,000		$	-
Cash paid for income tax	$	-		$	70,000
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	19,000		$	14,000
Accrued capital expenditures	$	903,000		$	267,000
Prepaid capital expenditures	$	-		$	345,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

~~December 31, 2012~~

1.	~~Basis of Presentation~~

The accompanying interim financial statements of Earthstone Energy, Inc. (formerly Basic Earth Science Systems, Inc.) are unaudited. However, in the opinion of management, the interim data includes any applicable adjustments necessary for a fair presentation of the financial and operational results for the interim period according to generally accepted accounting principles in the United States of America (“U.S. GAAP”).

At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout the notes to the unaudited condensed consolidated financial statements, they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and suggest that these financial statements be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the previous fiscal year-end.

~~Further, the results of operations for the three months and nine months covered by this report, are not necessarily indicative of the operating results that may be expected for the year.~~

~~Fair Value Measurements.~~ The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments.

~~Use of Estimates~~. The preparation of financial statements in conformity with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions concern matters that are inherently uncertain. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from those estimates.

~~Recent Accounting Pronouncements.~~ ~~In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210):~~ ~~Disclosures about Offsetting Assets and Liabilities.~~ This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company is required to implement this guidance effective for the first quarter of fiscal 2014 and does not expect the adoption of ASU 2011-11 to have a material impact on its consolidated financial statements.

2.	~~Other Assets~~

12/31/12 03/31/12
(Unaudited)
Drilling and completion cost prepayments $ 264,000 $ 230,000
Lease and well equipment inventory 323,000 412,000
Prepaid insurance premiums 33,000 73,000
Prepaid income tax 132,000 -
Other current assets 33,000 34,000

Total other current assets $ 785,000 $ 749,000

Earthstone Energy, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

June 30, 2013

3.1. Basis of Presentation

~~Accrued Liabilities~~

Further, the results of operations for the three months covered by this report, are not necessarily indicative of the operating results that may be expected for the full fiscal year.

Fair Value Measurements. The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments. The carrying value of the Company’s Credit Facility approximates its fair value, interest rates are variable based on prevailing market rates.

Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions concern matters that are inherently uncertain. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from those estimates.

Recent Accounting Pronouncements. In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company was required to implement this guidance effective for the first quarter of fiscal 2014. The adoption of ASU 2011-11 did not have a material impact on its consolidated financial statements.

2. Other Assets

12/31/12 03/31/12
(Unaudited)
Accrued operations payable $ 2,176,000 $ 1,472,000
Accrued compensation 341,000 445,000
Accrued income tax payable and other 263,000 393,000
Revenue and production taxes payable 116,000 167,000
Short term asset retirement obligation 303,000 133,000

Total accrued liabilities $ 3,199,000 $ 2,610,000

	06/30/13		03/31/13
	(Unaudited)
Lease and well equipment inventory	$	371,000	$	371,000
Drilling and completion cost prepayments		208,000		210,000
Prepaid income tax		82,000		112,000
Other current assets		60,000		33,000
Prepaid issuance premiums		59,000		88,000

Total other current assets	$	780,000	$	814,000

~~Oil and Gas Properties~~

12/31/12 03/31/12
(Unaudited)
Proved properties $ 48,166,000 $ 37,112,000
Unproved properties 2,908,000 4,409,000
Less accumulated depletion and impairment (27,062,000 ) (25,778,000 )

Total accrued liabilities $ 24,012,000 $ 15,743,000

As of December 31, 2012, the Company has recorded $48,166,000 as proved property costs. As of March 31, 2012, the Company had recorded $37,112,000 as proved property costs. Additions of $11,054,000 recorded during the nine months ended December 31, 2012 include $9,372,000 primarily related to intangible drilling costs and tangible completion costs in North Dakota. In addition, $1,682,000 in costs were transferred from unproved to proved properties.

As of December 31, 2012, the Company has recorded $2,908,000 as unproved property costs. As of March 31, 2012, the Company had recorded $4,409,000 as unproved property costs. As of December 31, 2012, the Company recorded additional unproved property costs of $181,000 and transferred $1,682,000 in costs from unproved to proved properties.

5.	~~Long Term Debt~~

On December 21, 2012, the Company entered into a $25 million senior secured revolving bank credit facility (the "Credit Facility") the Bank of Oklahoma (the "Bank"). The initial borrowing base on the Credit Facility is $6 million. The maturity date of the Credit Facility is December 21, 2017. The Credit Facility is secured by mortgages on certain Company properties and an assignment of all the proceeds from severed and extracted hydrocarbons from the properties described in the mortgages. Until further notice, the Bank has suspended their right to receive the proceeds directly.

The Credit Facility contains certain affirmative and negative covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. As of December 31, 2012, the Company is in compliance with all of the financial covenants under the Credit Facility.

Payments of interest are due quarterly in arrears at prime plus 0.75% to 1.75% or LIBOR plus 1.75% to 2.75%, depending on the Company's level of borrowing and election at the date of borrowing. Commitment fees on the unused amounts of the Credit Facility are due quarterly at rates from 0.35% to 0.50% on the unused amounts of the Credit Facility. At closing, the Company paid a borrowing base fee of $30,000, or 0.5%, on the $6 million borrowing base. These costs have been recorded as deferred financing costs and will be amortized over the term of the note. Additional borrowing base fees may be payable upon future increases in the borrowing base, if any. As of December 31, 2012, the Company had an outstanding balance under the Credit Facility of $2 million.

6.3. Accrued Liabilities

~~Income Tax~~

~~The provision for income tax is comprised of:~~

Three Months Ended December 31, Nine Months Ended December 31,
2012 2011 2012 2011
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
Current:
     Federal $ 13,000 $ 29,000 $ 36,000 $ 114,000
     State 1,000 5,000 4,000 15,000
Total current income tax 14,000 34,000 40,000 129,000

Deferred:
     Federal 80,000 438,000 149,000 648,000
     State 7,000 31,000 12,000 46,000
Total deferred income tax 87,000 469,000 161,000 694,000

Income tax expense $ 101,000 $ 503,000 $ 201,000 $ 823,000

	06/30/13		03/31/13
	(Unaudited)
Accrued operations payable	$	3,862,000	$	2,933,000
Accrued compensation		539,000		429,000
Accrued income tax payable and other		319,000		213,000
Short-term asset retirement obligation		301,000		296,000
Revenue and production taxes payable		108,000		100,000

Total accrued liabilities	$	5,129,000	$	3,971,000

~~A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the three months and nine months ended is as follows:~~

4. Oil and Gas Properties

	06/30/13			03/31/13
	(Unaudited)
Proved properties	$	58,374,000		$	53,265,000
Unproved properties		1,687,000			2,156,000
Less accumulated depletion and impairment		(28,488,000	)		(27,729,000	)

Total oil and gas properties	$	31,573,000		$	27,692,000

Three Months Ended December 31, Nine Months Ended December 31,
2012 2011 2012 2011
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
Federal tax at statutory rate $ 160,000 $ 562,000 $ 451,000 $ 1,145,000
State taxes, net of federal benefit 5,000 27,000 12,000 55,000
Excess percentage depletion (89,000 ) (163,000 ) (296,000 ) (371,000 )
Other adjustments, net 25,000 77,000 34,000 (6,000 )

Income tax expense $ 101,000 $ 503,000 $ 201,000 $ 823,000
Effective rate expressed as a percentage
of income before income tax 21.4 % 30.4 % 15.2 % 24.4 %

The overall effective tax rate expressed as a percentage of book income before income tax for the current three month period, as compared to the same period in the prior year, was lower due to nonrecurring adjustments recorded in the three months ended December 31, 2011. These adjustments were not necessary during the three months ended December 31, 2012.

As of June 30, 2013, the Company has recorded $58,374,000 as proved property costs. As of March 31, 2013, the Company had recorded $53,265,000 as proved property costs. Additions of $4,640,000 have been recorded during the three months ended June 30, 2013, included in these additions are $4,613,000 related to intangible drilling and completion costs and tangible drilling and completion costs. Of the total additions recorded during the three months ended June 30, 2013, 92% relate to our work in North Dakota.

As of June 30, 2013, the Company has recorded $1,687,000 as unproved property costs. As of March 31, 2013, the Company had recorded $2,156,000 as unproved property costs. For the three months ended June 30, 2013, the Company recorded additional unproved property costs of $138,000 related to wells in progress and $77,000 related to additional investments in unproved properties. During the three months ended June 30, 2013, $389,000 in well costs and $286,000 in costs related to acreage were transferred from unevaluated to depletable properties, in addition, there were leased acreage expirations of $9,000.

5. Long-Term Debt

During the quarter ended June 30, 2013, the Company drew $1 million on the Credit Facility. As of June 30, 2013, the Company had an outstanding balance under the Credit Facility of $5 million. As of June 30, 2013, we were not in compliance with the current ratio covenant as defined by the Credit Facility. In July 2013, a semiannual redetermination of the borrowing base was completed by the lender, subject to the satisfaction of increased collateral requirements being provided to the lender. The Company is in the process of providing the required documentation. The redetermination will result in an increase in the borrowing base from $6 million to $12 million. The increase in the borrowing base will result in the covenant violation being mitigated. The lender has not presented a notice of default related to this covenant violation to the Company. As of June 30, 2013 we were in compliance with all other covenants contained in the Credit Facility.

6. Income Tax

The provision for income tax is comprised of:

	Three Months Ended June 30,
	2013		2012
	(Unaudited)		(Unaudited)
Current:
Federal		20,000	$	11,000
State		7,000		1,000
Total current income tax		27,000		12,000

Deferred:
Federal		133,000		(4,000	)
State		8,000		-
Total deferred income tax		141,000		(4,000	)

Income tax expense		168,000	$	8,000

A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the three months ended is as follows:

	Three Months Ended June 30,
	2013			2012
	(Unaudited)			(Unaudited)
Federal tax at statutory rate	$	292,000		$	94,000
State taxes, net of federal benefit		9,000			-
Excess percentage depletion		(135,000	)		(93,000	)
Other adjustments, net		2,000			7,000

Income tax expense	$	168,000		$	8,000
Effective rate expressed as a percentage
of income before income tax		19.5	%		3	%

The overall effective tax rate expressed as a percentage of book income before income tax for the current three month period, as compared to the same period in the prior year, was higher due to a higher pre-tax income compared to the comparable prior period, coupled with a change in excess percentage depletion. For the current three month period, pre-tax income was $861,000 compared to $278,000 for the prior period.

Net deferred tax assets and liabilities were comprised of:

	December 31,			March 31,			June 30,			March 31,
	2012			2012			2013			2013
	(Unaudited)						(Unaudited)
Deferred tax assets:
Statutory depletion carry-forward	$	1,367,000		$	1,232,000		$	1,572,000		$	1,467,000
Asset retirement obligation		730,000			669,000
Other accruals		103,000			88,000			122,000			131,000
Allowance for doubtful accounts		14,000			22,000			14,000			14,000

Gross deferred tax assets		2,214,000			2,011,000			1,708,000			1,612,000

Deferred tax liabilities:
Depletion, depreciation and intangible drilling costs		(5,106,000	)		(4,742,000	)		(4,818,000	)		(4,583,000	)

Gross deferred tax liabilities		(5,106,000	)		(4,742,000	)		(4,818,000	)		(4,583,000	)

Deferred tax liabilities, net	$	(2,892,000	)	$	(2,731,000	)	$	(3,110,000	)	$	(2,971,000	)

Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.

The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions.

The Company’s federal income tax returns for the prior three tax years of filings and state income tax returns for the prior four years of tax filings are still subject to examination by tax authorities.

~~The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions.~~

~~The Company's tax returns for the prior four tax years of filings are still subject to examination by tax authorities.~~

1112

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in ~~the Company’s~~our Annual Report on Form 10-K for the year ended March 31, ~~2012,~~2013, as well as the unaudited condensed consolidated financial statements and related notes and other information appearing in Item 1 of this report.

The preparation of ~~the Company’s~~our unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the reported amounts in the unaudited condensed consolidated financial statements and the accompanying notes including matters arising during the normal course of business. We apply our best judgment, our knowledge of existing facts and circumstances and our knowledge of actions that we may undertake in the future in determining the estimates that will affect our unaudited condensed consolidated financial statements. We evaluate our estimates on an ongoing basis using our historical experience, as well as other factors we believe appropriate under the circumstances, such as current economic conditions, and adjust or revise our estimates as circumstances change. As future events and their effects cannot be determined with precision, actual results may differ from these estimates.

As used in this report, unless the context otherwise indicates, references to “we,” “our,” and “us” refer to Earthstone Energy, Inc. and its subsidiary collectively.

As an oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are influenced by the prevailing prices of crude oil and natural gas. Changes in commodity prices affect, both positively and negatively, our financial condition, liquidity, ability to obtain financing and operating results. Changes in commodity prices may influence, both positively and negatively, the amount of crude oil and natural gas that we choose to produce. Prevailing prices for such commodities fluctuate in response to changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Inherently, the prices received for crude oil and natural gas production are unpredictable, and such volatility is expected. Most of our production is sold at market prices. Obviously, if the commodity indexes fluctuate, the price that we receive for our production will fluctuate. Therefore, the amount of revenue that we realize, as well as our estimates of future revenues, is to a large extent determined by factors beyond our control.

Liquidity and Capital Resources

Liquidity Outlook. Our primary source of funding is the net cash flow from the sale of our oil and natural gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. At the current price of oil, we believe the cash generated from operations, along with existing cash balances and available line of credit, should enable us to meet our existing and normal recurring obligations during the next year and beyond.

On December 21, 2012, we entered into a $25 million senior secured revolving bank Credit Facility with the Bank of Oklahoma which is intended to provide an additional source of funds to pay our share of drilling and completion costs incurred on wells drilled and completed in the Williston Basin. The initial borrowing base on the Credit Facility is $6 million and, as of ~~December 31, 2012,~~June 30, 2013, we had an outstanding balance of $2$5 million. Among other provisions, the Credit Facility contains certain affirmative and negative covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. As of ~~December 31, 2012,~~June 30, 2013, we were not in compliance with the current ratio covenant as defined by the Credit Facility. In July 2013, a semiannual redetermination of the borrowing base was completed by the lender, subject to the satisfaction of increased collateral requirements being provided to the lender. The Company is in the process of providing the required documentation. The redetermination will result in an increase in the borrowing base from $6 million to $12 million. The increase in the borrowing base will result in the covenant violation being mitigated. The lender has not presented a notice of default related to this covenant violation to the Company. As of June 30, 2013 we were in compliance with all ~~of the financial~~other covenants ~~under~~contained in the Credit Facility. Our ability to remain in compliance with the financial covenants may be affected by events and other factors beyond our control, including market prices for our oil and ~~gas.~~gas and the rate at which the operators of projects in which we participate drill. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect our liquidity by rendering us unable to borrow further under the Credit Facility. For further information concerning the Credit Facility and its terms, see our Form 8-K filed with the SEC on January 3, ~~2013 and footnote 5 to our unaudited financials set forth herein.~~2013.

1213

Overview of our Capital Structure. We recognize the importance of developing our capital resource base in order to pursue our objectives. However, subsequent to our last public offering in 1980, debt financing has been the sole source of external funding. In addition to our routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, we require capital to fund our exploratory and development drilling efforts and the acquisition of additional properties as well as the enhancement of ~~held~~existing and newly acquired properties.

We have received numerous inquiries regarding the possibility of funding our efforts through equity contributions. Given strong cash flows, we have thus far declined these overtures. Our primary concern in this area is the dilution of our existing shareholders. However, going forward, given that one of the key components of our growth strategy is to expand our oil and natural gas reserve base through drilling and/or acquisitions, if we were presented with a significant opportunity and available cash and bank debt financing were insufficient, it is possible we would consider alternative ~~forms~~means of obtaining additional financing.

Hedging. During the three months ended ~~December 31,~~June 30, 2013 and 2012, ~~and 2011,~~ we did not participate in any hedging activities, nor did we have any open futures or option contracts.

Working Capital. At ~~December 31, 2012,~~June 30, 2013, we had a working capital ~~surplus~~deficit of ~~$1,646,000~~$1,282,000 (a current ratio of ~~1.37:~~0.82:1) compared to a working capital surplus at March 31, ~~2012~~2013 of ~~$6,572,000~~$775,000 (a current ratio of ~~2.91:~~1.14:1). The decrease in current ratio is primarily a result of the use of ~~cash~~accounts payable and accrued operations payable for the development and exploration of oil and gas properties ~~coupled with a decrease in cash provided by operations as discussed further below.~~and ongoing oil and gas operations.

Cash Flow. Cash provided by operating activities was ~~$1,982,000~~$2,888,000 for the ~~nine~~three months ended ~~December 31, 2012,~~June 30, 2013, compared to ~~$3,084,000~~cash used in operating activities $42,000 for the ~~nine~~three months ended ~~December 31, 2011.~~June 30, 2012. Changes in operating cash relate primarily to the ~~decline~~increase in net income adjusted for non-cash expenses for the ~~nine~~three months ended ~~December 31, 2012~~June 30, 2013 compared to the same period ended ~~December 31, 2011.~~June 30, 2012. The fluctuation in deferred income tax expense, the increase in depletion primarily related to the increase in the oil and gas property balance, the timing and payment of accounts payable, accrued and ~~accrued~~other liabilities, especially pertaining to capital expenditure outlays, in addition to ~~the timing and collection of accounts receivable and~~ the application of prepaid balances were also factors in deriving net cash flows from operations.

Overall, net cash used in investing activities increased for the ~~nine~~three months ended ~~December 31, 2012,~~June 30, 2013, to ~~$8,573,000~~$3,862,000 from ~~$4,759,000~~$2,150,000 for the ~~nine~~three months ended ~~December 31, 2011.~~June 30, 2012. This was the result of an increase in the number of wells drilled and completed during the current period compared to the same period in the prior year, ~~in addition to spending on the acquisitions of oil and gas property,~~ as explained in “Capital Expenditures” below.

Net cash provided by financing activities was ~~$1,970,000~~$996,000 for the ~~nine~~three months ended ~~December 31, 2012~~June 30, 2013 related to ~~$2 million in~~ borrowing on ~~a bank credit facility net of related financing fees of $30,000 paid in cash. Net~~our Credit Facility. No cash was provided by or used in financing activities ~~was $84,000~~ for the ~~nine~~three months ended ~~December 31, 2011 related to the purchase of treasury shares.~~June 30, 2012.

Capital Expenditures

The amounts presented herein are presented on an accrual basis, and as such may not be consistent with the amounts presented on the condensed consolidated statements of cash flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.

During the ~~nine~~three months ended ~~December 31, 2012,~~June 30, 2013, we spent ~~$9,553,000~~$4,640,000 on various projects. This compares to ~~$5,427,000~~$2,748,000 for the ~~nine~~three months ended ~~December 31, 2011.~~June 30, 2012. During the ~~nine~~three months ended ~~December 31, 2012,~~June 30, 2013, capital expenditures were comprised of the drilling and ~~completion~~completions of our wells producing as of period end ~~($5,141,000 or 54%~~(24%), ~~the~~ drilling of 16 wells to be completed as of ~~fiscal~~calendar year end ~~($3,811,000 or 40%~~(72%), and acquiring leasehold ~~expenditures ($304,000 or 3%~~acreage (4%). The ~~remaining costs ($297,000 or 3%~~majority (92%) of capital expenditures were ~~primarily related to recompleting existing wells~~spent in the Williston basin. The remainder was spent in other areas on property improvements and ~~miscellaneous costs. These costs were funded primarily with internally generated cash flow and cash on hand.~~leasehold acreage.

We are continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of evaluation. Our policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken. We caution that the absence of news and/or press releases should not be interpreted as a lack of development or activity.

Divestitures/Abandonments

We neither sold nor plugged any wells during the ~~nine~~three months ended ~~December 31, 2012.~~June 30, 2013.

Impact of Inflation and Pricing

Inflation has not had a material impact on ~~the Company~~us in recent years because of the relatively low rates of inflation in the United States. However, the oil and natural gas industry can be cyclical and the demand for production places pressure on the economic stability and pricing within the industry. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, cost declines are likely to lag and may not adjust downward in proportion to declining prices. Changes in prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel. While we do not presently expect business costs to materially rise, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

~~Reserves~~

During the nine months ended December 31, 2012, proved reserves in barrels of oil equivalent (“BOE”) increased 42% from 1,335,000 at March 31, 2012 to 1,895,000 at December 31, 2012. The reserve balance reflects the favorable impact of newly developed reserves offset by the natural decline curve for existing wells.

Other Commitments

We do not have any other commitments beyond our office lease and software maintenance contracts.

1415

Results of Operations

The following provides selected financial information and averages for the three ~~and nine~~ months ended ~~December 31, 2012~~June 30, 2013 and ~~2011.~~

2012.

Production taxes for the three months ended ~~December 31, 2012, decreased 32%~~June 30, 2013 increased 58% over the three months ended ~~December 31, 2011.~~June 30, 2012. As a percent of oil and gas sales revenue, production taxes remained the same between the two periods at 9%. Because production tax rates vary from state to state our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those jurisdictions.

While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) ~~decreased~~increased during the current quarter in relation to the comparable period in the prior year, those costs are spread over ~~smaller~~larger reported volumes, per BOE, for the three months ended ~~December 31, 2012,~~June 30, 2013, compared to the three months ended ~~December 31, 2011,~~June 30, 2012, causing the costs per BOE to ~~increase~~decrease from ~~$27.01~~$35.00 to ~~$30.72.~~$27.45.

Other Expenses.

Depletion and depreciation increased ~~$214,000 (59%~~$492,000 (167%) for the three months ended ~~December 31, 2012,~~June 30, 2013, compared to the three months ended ~~December 31, 2011.~~June 30, 2012. The increase in expense was a result of the addition of capital costs for newly drilled wells transferred into the pool of depletable property costs, ~~offset partially by~~as well as an increase in ~~total reserves and~~costs related to future development of proved undeveloped wells, offset by a slight decrease in the depletion rate due to a smaller volume of BOE production to total reserves during the current quarter.

General and Administrative (“G&A”) expense increased ~~$196,000 (41%~~$12,000 (2%) for the three months ended ~~December 31, 2012,~~June 30, 2013, over the expense for the three months ended ~~December 31, 2011. This rise~~June 30, 2012. While G&A expense increased slightly during the current quarter in relation to the comparable period in the prior year, those costs ~~is comprised primarily of compensation-related expenses for additional employees, contract labor and consultants.~~

~~The escalation in G&A costs resulted in a 94% increase in expense~~are spread over larger reported volumes, per BOE, ~~from $9.58~~ for the three months ended ~~December 31, 2011,~~June 30, 2013, compared to ~~$18.60 for~~ the three months ended ~~December 31, 2012.~~June 30, 2012, causing the costs per BOE to decrease from $23.14 to $16.63.

Income Tax.For the three months ended ~~December 31, 2012,~~June 30, 2013, we recorded income tax expense of ~~$101,000,~~$168,000, as compared to ~~$503,000~~$8,000 for the three months ended ~~December 31, 2011.~~June 30, 2012. Our effective income tax rate was ~~21.4%~~19.5% for the three months ended ~~December 31, 2012.~~June 30, 2013. The overall effective tax rate expressed as a percentage of book income before income tax for the three months ended ~~December 31, 2012,~~June 30, 2013, as compared to the same period in ~~2011,~~2012, was ~~lower~~higher due primarily to ~~nonrecurring adjustments~~a higher pre-tax income compared to the comparable prior period coupled with a change in excess percentage depletion. For the three months ended ~~December 31, 2011. These adjustments were not necessary during the three months ended December 31, 2012.~~

~~Nine months ended December 31, 2012~~June 30, 2013, pre-tax income was $861,000 compared to ~~nine months ended December 31, 2011~~

~~Overview.~~ ~~Net income~~$278,000 for the nine months ended December 31, 2012, was $1,126,000 compared to net income of $2,545,000 for the nine months ended December 31, 2011. The decrease in net income resulted from the decline in oil prices and volumes coupled with a decrease in gas sales revenue as described in “Revenues” and “Volumes and Prices” below and an increase in expenses for the three monthprior period.

~~Revenues~~. Oil sales revenue declined $518,000 (7%) for the nine months ended December 31, 2012, from $7,781,000 for the nine months ended December 31, 2011 to $7,263,000 for the current period, due to a 10% lower realized price per barrel, partially offset by a 4% increase in production volume as described in “~~Volumes and Prices”~~ ~~below.~~

Gas sales revenue decreased $625,000 (60%) for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011, as a result of having divested the Company’s working and/or override interests in 38 gas wells in Weld County, Colorado in January of 2012.

~~Volumes and Prices~~. Oil sales volumes rose by 4% for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011. The average price per barrel declined by 10% for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011. The rise in oil sales volumes for the nine months ended December 31, 2012 was the result of the net contribution from newly producing horizontal Bakken wells in North Dakota drilled this year versus steep declines in production on previously producing horizontal Bakken wells since the comparable period in the prior year.

The divestiture of the Company’s working and/or override interests in 38 wells in Weld County, Colorado since the comparable prior year period ended December 31, 2011, resulted in the decline in our reported natural gas production. As of December 31, 2012, we hold interests in 3 gas wells. The 22% drop in average price per Mcf for the nine months ended December 31, 2012, compared to the respective period in the prior year had only a minor impact relative to the divestiture of the aforementioned properties.

~~Production Expense~~. ~~Production expense is comprised of the following items:~~

Nine Months Ended
December 31,

2012 2011

Lease operating costs $ 1,903,000 $ 1,678,000
Workover costs 573,000 665,000
Production taxes 697,000 688,000
Transportation and other costs 47,000 261,000

Total production expense $ 3,220,000 $ 3,292,000

Oil and gas production expense decreased $72,000 (2%) for the nine months ended December 31, 2012, over the expenses for the nine months ended December 31, 2011, largely due to the reduction in transportation costs (associated with divested Colorado properties) and a reduction in workover costs, partially offset by increases in lease operating costs due to the increase in the number of producing wells.

Routine lease operating expense (“LOE”), consisting of field personnel, fuel/power, chemicals, disposal and other costs, per BOE was $19.17 for the nine months ended December 31, 2012, compared to $17.64 for the nine months ended December 31, 2011. Increases in lease operating costs were partially offset by reductions in transportation costs and total production expense in the nine months ended December 31, 2012. The slight increase in routine lease operating expense was allocated over a smaller production volume than in the nine months ended December 31, 2011 resulting in the increase in cost per BOE.

~~As a percent of oil and gas sales revenue, routine LOE was 25% for the nine months ended December 31, 2012 and 22% for the nine months ended December 31, 2011.~~

~~Workover~~ ~~operations, which generally consist of~~ ~~downhole repairs~~ ~~on a producing well, are conducted to restore or increase production~~ and are generally random in nature. Therefore, workovers account for unpredictable fluctuations in oil and gas expense from period to period. The number of wells on which workover costs are expended varies as does the extent of workover operations. Workover expenses decreased $92,000 (14%) for the nine months ended December 31, 2012, compared to the respective period ended December 31, 2011 resulting in a decrease in workover costs per BOE in the nine months ended December 31, 2012 to $5.63 from $6.05 per BOE in the nine months ended December 31, 2011.

Production taxes for the nine months ended December 31, 2012, increased 1% over the nine months ended December 31, 2011. As a percent of oil and gas sales revenue, production taxes rose from 8% to 9% for the respective prior year nine month period. Because production tax rates vary from state to state our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those jurisdictions.

While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) decreased slightly during the current period, those costs are spread over smaller reported volumes per BOE, for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011, causing the cost per BOE to increase from $29.95 to $31.66.

~~Other Expenses~~.

Depletion and depreciation increased $544,000 (69%) for the nine months ended December 31, 2012, compared to the nine months ended December 31, 2011. The increase in expense was a result of the addition of capital costs for newly drilled wells transferred into the pool of depletable property costs offset partially by an increase in total reserves and the smaller volume of BOE production during the current nine months.

General and Administrative expense increased $555,000 (39%) for the nine months ended December 31, 2012, over the expense for the nine months ended December 31, 2011. This rise in costs is comprised primarily of compensation-related expenses for additional employees, contact labor and consultants, which account for $492,000 of the increase. Public company expenses and state franchise taxes were up $39,000 and $35,000, respectively, for the nine month period.

~~The escalation in G&A costs resulted in the 50% increase in expense per BOE from $12.94 for the nine months ended December 31, 2011, to $19.44 for the nine months ended December 31, 2012.~~

~~Income Tax~~. For the nine months ended December 31, 2012, we recorded income tax expense of $201,000, as compared to $823,000 for the nine months ended December 31, 2011. Our effective income tax rate was 15.2% for the nine months ended December 31, 2012. The overall effective tax rate expressed as a percentage of book income before income tax for the nine months ended December 31, 2012, as compared to the same period in 2011, was lower due primarily to lower pre-tax income and increased capital expenditures in the current period compared to the same period in the prior year.

Off Balance Sheet Arrangements

We have no significant off balance sheet transactions, arrangements or obligations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a “smaller reporting company,” we are not required to provide this information.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the phrase “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of ~~December 31, 2012.~~June 30, 2013. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Interim Chief Financial Officer concluded that, as of ~~December 31, 2012,~~June 30, 2013, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

2019

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

As a “smaller reporting company,” we are not required to provide this information.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

Not applicable.

Purchases of Equity Securities

The following summarizes monthly share repurchase activity for the ~~third~~first quarter of the fiscal year ending March 31, ~~2013:~~2014:

	Total Number of Shares Purchased¹		Average Price Paid Per Share		Number of Shares Purchased as Part of a Publicly Announced Plan¹		Maximum Shares that May Yet be Purchased under the Plan¹

~~October~~April 1, ~~2012~~2013 – ~~October 31, 2012~~April 30, 2013		-—	$	-—		-—		103,284
May 1, 2013 – May 31, 2013		—	$	—
~~November 1, 2012 – November 30, 2012~~		-	$	-		-—		103,284
~~December~~June 1, ~~2012~~2013 – ~~December 31, 2012~~June 30, 2013		-—	$	-—		-—		103,284
Total		-—				-—

On October 22, 2008, the Company’s Board of Directors authorized a share buyback program for the Company to repurchase up to 50,000 pre-split shares of its common stock for a period of up to 18 months. The program does not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time. On November 13, 2009, the Board of Directors increased the number of shares authorized for repurchase to 150,000 pre-split shares. On February 10, 2010, the Board extended the termination date of the program from April 22, 2010 to October 22, 2011. On November 7, 2011, the Board further extended the termination date of the program from October 22, 2011 to October 22, 2013. During the quarter ended December 31, 2012, no shares were repurchased under the share buyback program and 103,284 shares (11,067 post-split shares) remain available for future repurchase.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

Exhibit No.		Document

31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).

31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Paul D. Maniscalco, Interim Chief Financial Officer).

32.1		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).

32.2		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Paul D. Maniscalco, Interim Chief Financial Officer).

101		The following materials from the Company’s quarterly report on Form 10-Q for the quarter ended ~~December 31, 2012,~~June 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Statements of Operations, (ii) the Unaudited Condensed Consolidated Balance Sheets, (iii) the Unaudited Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Unaudited Condensed Consolidated Financial Statements, tagged as blocks of text.

2221

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed by the following authorized persons on behalf of Earthstone Energy, Inc.

	EARTHSTONE ENERGY, INC.

Date: ~~February 8,~~August 12, 2013	By:	~~By:~~	/s/ Ray Singleton
		Ray Singleton
		President and Chief Executive Officer


	By:	/s/ Paul D. Maniscalco
		Paul D. Maniscalco
		Interim Chief Financial Officer

									Three Months Ended
		Three Months Ended December 31,				Nine Months Ended December 31,			June 30,
		2012		2011		2012		2011	2013		2012
Revenue
Oil	$	2,589,000	$	3,409,000	$	7,263,000	$	7,781,000	$	3,380,000	$	2,128,000
Gas		163,000		421,000		409,000		1,034,000		202,000		92,000
Total revenue 1		2,752,000		3,830,000		7,672,000		8,815,000		3,582,000		2,220,000

Total production expense 2		1,105,000		1,333,000		3,220,000		3,292,000		1,144,000		1,030,000

Gross profit	$	1,647,000	$	2,497,000	$	4,452,000	$	5,523,000	$	2,438,000	$	1,190,000

Depletion expense	$	559,000	$	350,000	$	1,284,000	$	752,000	$	760,000	$	279,000

Sales volume
Oil (Bbls)		31,549		38,809		89,717		86,427		36,967		26,999
Gas (Mcfs) 3		26,542		63,281		71,926		140,943		28,223		14,566

Average sales price 4
Oil (per Bbl)	$	82.06	$	87.84	$	80.95	$	90.03	$	91.43	$	78.82
Gas (per Mcf)	$	6.14	$	6.65	$	5.69	$	7.34	$	7.16	$	6.32

Average per BOE 5
Production expense 3, 4	$	30.72	$	27.01	$	31.66	$	29.95	$	27.45	$	35.00
Gross profit 4	$	45.78	$	50.59	$	43.77	$	50.25	$	58.51	$	40.44
Depletion expense 4	$	15.54	$	7.09	$	12.62	$	6.84	$	18.24	$	9.48

1		Amount does not include water service and disposal revenue. For the three ~~and nine~~ months ended ~~December 31, 2012,~~June 30, 2013, this revenue amount is net of ~~$82,000 and $318,000, respectively,~~$13,000 in well service and water disposal revenue, which would otherwise total ~~$2,834,000 and $7,990,000, respectively,~~$3,595,000 in revenue, compared to ~~$36,000 and $121,000~~$127,000 in the respective periods ended ~~December 31, 2011,~~June 30, 2012 to total ~~$3,866,000 and $8,936,000~~$2,347,000 for the comparable three ~~and nine~~ month ~~periods~~period ended ~~December 31, 2011.~~
		June 30, 2012.
2		Overall lifting cost (oil and gas production costs, including production taxes and the cost of workovers)

3		Estimates of volumes are inherent in reported volumes to coincide with revenue accruals as a result of the timing of sales information reporting by third party operators.

4		Averages calculated based upon non-rounded ~~figures~~
		figures.
5		Per equivalent barrel (6 thousand cubic feet, “Mcf”, of gas is equivalent to 1 barrel, “Bbl”, of oil)

	Three Months Ended					Nine Months Ended
	December 31,					December 31,
	2012			2011		2012			2011
Revenues:
Oil and gas sales	$	2,752,000		$	3,830,000	$	7,672,000		$	8,815,000
Well service and water-disposal revenue		82,000			36,000		318,000			121,000

Total revenues		2,834,000			3,866,000		7,990,000			8,936,000

Expenses:
Oil and gas production		866,000			983,000		2,523,000			2,610,000
Production tax		239,000			350,000		697,000			688,000
Well service and water-disposal		18,000			-		60,000			-
Depletion and depreciation		577,000			363,000		1,332,000			788,000
Accretion of asset retirement obligation		43,000			43,000		130,000			125,000
General and administrative		669,000			473,000		1,977,000			1,422,000

Total expenses		2,412,000			2,212,000		6,719,000			5,633,000

Income from operations		422,000			1,654,000		1,271,000			3,303,000

Other income (expense):
Interest and other income		51,000			1,000		59,000			68,000
Interest and other expenses		(2,000	)		-		(3,000	)		(3,000	)

Total other income		49,000			1,000		56,000			65,000

Income before income tax		471,000			1,655,000		1,327,000			3,368,000

Current income tax expense		14,000			34,000		40,000			129,000
Deferred income tax expense		87,000			469,000		161,000			694,000

Total income tax expense		101,000			503,000		201,000			823,000

Net income	$	370,000		$	1,152,000	$	1,126,000		$	2,545,000

Per share amounts:
Basic	$	0.22		$	0.68	$	0.65		$	1.49
Diluted	$	0.22		$	0.68	$	0.65		$	1.49

Weighted average common shares outstanding:
Basic		1,720,712			1,706,588		1,720,712			1,710,035
Diluted		1,720,712			1,706,588		1,720,712			1,710,035

	12/31/12		03/31/12
	(Unaudited)
Drilling and completion cost prepayments	$	264,000	$	230,000
Lease and well equipment inventory		323,000		412,000
Prepaid insurance premiums		33,000		73,000
Prepaid income tax		132,000		-
Other current assets		33,000		34,000

Total other current assets	$	785,000	$	749,000

	Three Months Ended December 31,				Nine Months Ended December 31,
	2012		2011		2012		2011
	(Unaudited)		(Unaudited)		(Unaudited)		(Unaudited)
Current:
Federal	$	13,000	$	29,000	$	36,000	$	114,000
State		1,000		5,000		4,000		15,000
Total current income tax		14,000		34,000		40,000		129,000

Deferred:
Federal		80,000		438,000		149,000		648,000
State		7,000		31,000		12,000		46,000
Total deferred income tax		87,000		469,000		161,000		694,000

Income tax expense	$	101,000	$	503,000	$	201,000	$	823,000

	Three Months Ended December 31,				Three Months Ended June 30,
		2012		2011	2013		2012

Lease operating costs	$	654,000	$	601,000	$	697,000	$	658,000
Workover costs		186,000		304,000		116,000		171,000
Production taxes		239,000		350,000		309,000		196,000
Transportation and other costs		26,000		78,000		22,000		5,000

Total production expense	$	1,105,000	$	1,333,000	$	1,144,000	$	1,030,000