UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended December 31, 2011

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

Commission file number: 0-7914

(Exact Name of Registrant as Specified in its Charter)

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

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

(303) 296-3076

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

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 10, 2012: 1,706,756

EARTHSTONE ENERGY, INC.

FORM 10-Q

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements		4
	Condensed Consolidated Balance Sheets:
	December 31, 2011 (Unaudited) and March 31, 2011		4
	Condensed Consolidated Statements of Operations:
	Three and Nine months Ended December 31, 2011 and 2010 (Unaudited)		6
	Condensed Consolidated Statements of Cash Flows:
	Nine months Ended December 31, 2011 and 2010 (Unaudited)		7
	Notes to Unaudited Condensed Consolidated Financial Statements:
	December 31, 2011		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		15
Item 4.	Controls and Procedures		15
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		16
Item 1A.	Risk Factors		16
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		16
Item 3.	Defaults Upon Senior Securities		16
Item 4.	Submission of Matters to a Vote of Security Holders		16
Item 5.	Other Information		16
Item 6.	Exhibits		17
	Signatures		18

2

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;

• 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;

• 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.

3

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

Page 1 of 2

	December 31,			March 31,
	2011			2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,292,000		$	4,051,000
Accounts receivable:
Oil and gas sales		2,851,000			1,674,000
Joint interest and other receivables, net of allowance of $37,000                and $86,000 in allowance, respectively		90,000			329,000
Other current assets		499,000			539,000
Total current assets		5,732,000			6,593,000
Oil and gas property, full cost method:
Proved property		37,324,000			35,379,000
Unproved property		6,463,000			3,112,000
Accumulated depletion and impairment		(25,465,000	)		(24,713,000	)
Net oil and gas property		18,322,000			13,778,000
Support equipment and other non-current assets, net of accumulated    depreciation of $402,000 and $377,000, respectively		531,000			471,000
Total non-current assets		18,853,000			14,249,000
Total assets	$	24,585,000		$	20,842,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

4

Earthstone Energy, Inc.

Condensed Consolidated Balance Sheets

Page 2 of 2

	December 31,			March 31,
	2011			2011
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	409,000		$	496,000
Accrued liabilities		1,827,000			1,167,000
Total current liabilities		2,236,000			1,663,000
Long-term liabilities:
Deferred tax liability		3,013,000			2,319,000
Asset retirement obligation		1,744,000			1,795,000
Total long-term liabilities		4,757,000			4,114,000
Commitments
Total liabilities		6,993,000			5,777,000
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  1,788,000 and 1,782,000 shares issued, respectively		18,000			18,000
Additional paid-in capital		23,086,000			23,020,000
Treasury stock, at cost, 82,000 and 76,000 shares, respectively		(457,000	)		(373,000	)
Accumulated deficit		(5,055,000	)		(7,600,000	)
Total shareholders’ equity		17,592,000			15,065,000
Total liabilities and shareholders’ equity	$	24,585,000		$	20,842,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

5

Earthstone Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended					Nine months Ended
	December 31,					December 31,
	2011		2010			2011			2010
Revenues:
Oil and gas sales	$	3,830,000	$	1,946,000		$	8,815,000		$	5,679,000
Well service and water disposal revenue		36,000		41,000			121,000			69,000
Total revenues		3,866,000		1,987,000			8,936,000			5,748,000
Expenses:
Oil and gas production		983,000		747,000			2,610,000			1,868,000
Production tax		350,000		130,000			688,000			403,000
Depletion and depreciation		363,000		274,000			788,000			842,000
Accretion of asset retirement obligation		43,000		43,000			125,000			124,000
General and administrative		473,000		392,000			1,422,000			1,113,000
Total expenses		2,212,000		1,586,000			5,633,000			4,350,000
Income from operations		1,654,000		401,000			3,303,000			1,398,000
Other income (expense):
Interest and other income		1,000		3,000			68,000			11,000
Interest and other expenses		―		(33,000	)		(3,000	)		(33,000	)
Total other income (expense)		1,000		(30,000	)		65,000			(22,000	)
Income before income tax		1,655,000		371,000			3,368,000			1,376,000
Current income tax expense (benefit)		34,000		(11,000	)		129,000			88,000
Deferred income tax expense		469,000		308,000			694,000			112,000
Total income tax expense		503,000		297,000			823,000			200,000
Net income	$	1,152,000	$	74,000		$	2,545,000		$	1,176,000
Per share amounts:
Basic	$	0.68	$	0.04		$	1.49		$	0.69
Diluted	$	0.68	$	0.04		$	1.49		$	0.69
Weighted average common shares outstanding:
Basic		1,706,588		1,697,097			1,710,035			1,699,877
Diluted		1,706,588		1,697,097			1,710,035			1,699,877

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

6

Earthstone Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

		Nine months Ended
		December 31,
		2011			2010
Cash flows from operating activities:
Net income	$	2,545,000		$	1,176,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and depreciation		788,000			842,000
Deferred income tax expense		694,000			112,000
Accretion of asset retirement obligation		125,000			124,000
Payments on asset retirement obligation		―			(264,000	)
Share-based compensation		66,000			57,000
Change in:
Accounts receivable, net		(938,000	)		29,000
Other current assets		62,000			128,000
Accounts payable, accrued and other liabilities		122,000			208,000
Net cash provided by operating activities		(258,000	)		2,412,000
Cash flows from investing activities:
Oil and gas property		(4,663,000	)		(3,114,000	)
Purchases of support equipment and other non-current assets		(96,000	)		(49,000	)
Net cash used in investing activities		(4,759,000	)		(3,163,000	)
Cash flows from financing activities:
Purchase of treasury shares		(84,000	)		(107,000	)
Net cash used in financing activities		(84,000	)		(107,000	)
Cash and cash equivalents:
Net decrease in cash and cash equivalents		(1,759,000	)		(858,000	)
Cash and cash equivalents, beginning of year		4,051,000			4,905,000
Cash and cash equivalents, end of period	$	2,292,000		$	4,047,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	―		$	―
Cash paid for income tax	$	1,000		$	214,000
Non-cash:
Increase in oil and gas property due to asset retirement         obligation	$	10,000		$	261,000
Accrued capital expenditures	$	957,000		$	296,000

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

7

Earthstone Energy, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

December 31, 2011

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" 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 year ended March 31, 2011.

The results of operations for the three and nine months ended December 31, 2011, are not necessarily indicative of the operating results that may be expected for the year ending March 31, 2012.

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.

Commitments.  As of December 31, 2011, the Company is committed to a total of $96,000 plus maintenance fees for a lease ending April 30, 2013 on a newly expanded 6,200 square foot office space located in downtown Denver, Colorado.  The Company does not have any off-balance sheet financing transactions, arrangements or obligations.

8

2. Accrued Liabilities

	December 31, 2011		March 31, 2011
	(Unaudited)
Revenue and production taxes payable	$	184,000	$	340,000
Accrued compensation		238,000		223,000
Accrued operations payable		1,094,000		239,000
Accrued income tax payable and other		180,000		238,000
Short term asset retirement obligation		131,000		127,000
Total accrued liabilities	$	1,827,000	$	1,167,000

Operations payable includes accrued capital expenditures, which totaled $957,000 at December 31, 2011, compared to $126,000 at March 31, 2011, with the balance pertaining to working interest owner distributions.

3. Income Tax

The provision for income tax for the three and nine months ended December 31, 2011 and 2010 is comprised of:

	Three Months Ended December 31,						Nine months Ended December 31,
	2011		2010				2011		2010
	(Unaudited)		(Unaudited)				(Unaudited)		(Unaudited)
Current:
Federal	$	29,000		$	1,000		$	114,000	$	92,000
State		5,000			(12,000	)		15,000		(4,000	)
Total current income tax		34,000			(11,000	)		129,000		88,000
Deferred:
Federal		438,000			90,000			648,000		77,000
State		31,000			218,000			46,000		35,000
Total deferred income tax		469,000			308,000			694,000		112,000
Income tax expense	$	503,000		$	297,000		$	823,000	$	200,000

9

A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the three and nine months ended December 31, 2011 and 2010 follows:

	Three Months Ended December 31,						Nine months Ended December 31,
	2011			2010			2011			2010
	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
Federal tax at statutory rate	$	562,000		$	278,000		$	1,145,000		$	468,000
State taxes, net of federal benefit		27,000			(1,000	)		55,000			17,000
Excess percentage depletion		(163,000	)		(48,000	)		(371,000	)		(170,000	)
Other adjustments, net		77,000			68,000			(6,000	)		(115,000	)
Income tax expense	$	503,000		$	297,000		$	823,000		$	200,000
Effective rate expressed as a percentage of income before income tax		30.4	%		80.1	%		24.4	%		14.5	%

The overall effective tax rate expressed as a percentage of book income before income tax for the nine months ended December 31, 2011, as compared to the same period in 2010, was higher due primarily to true-up adjustments from amounts originally estimated on prior year tax provisions in connection with the finalization of the tax returns.

Net income tax payments were $1,000 and $214,000 for the nine months ended December 31, 2011 and 2010, respectively.

Net deferred tax assets and liabilities as of December 31, 2011 and March 31, 2011 were comprised of:

	December 31,			March 31,
	2011			2011
	(Unaudited)
Deferred tax assets:
Allowance for doubtful accounts	$	14,000		$	34,000
Asset retirement obligation		683,000			703,000
Statutory depletion carry-forward		1,348,000			1,110,000
Gross deferred tax assets		2,045,000			1,847,000
Other accruals		68,000			69,000
Depletion, depreciation and intangible drilling costs		(5,126,000	)		(4,235,000	)
Gross deferred tax liabilities		(5,058,000	)		(4,166,000	)
Deferred tax liabilities, net	$	(3,013,000	)	$	(2,319,000	)

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 tax years remaining subject to examination by tax authorities are the years ended March 31, 2008 through 2011.

4. Subsequent Event

On January 31, 2012, we completed the divestiture and sale of the Company’s working and/or override interests in 38 wells in Weld County, Colorado to an unrelated third party for $5,900,000. After customary post-closing adjustments and expenses, the net proceeds from the transaction are expected to be $5,300,000. The adjusted purchase price was impacted by commissions, sales costs and post effective date revenue and expense modifications to the purchase price. The wells were considered non-core properties for the Company, given the Company’s focus on other areas, primarily the Williston Basin.

10

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 our Annual Report on Form 10-K for the year ended March 31, 2011, 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 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 substantially dependent upon the prevailing prices of crude oil and natural gas.  Declines in commodity prices will materially and adversely affect our financial condition, liquidity, ability to obtain financing and operating results.  Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically.  Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions.  Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue.  Most of our production is sold at market prices.  Generally, if the commodity indexes fall, the price that we receive for our production will also decline.  Therefore, the amount of revenue that we realize 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, should enable us to meet our existing and normal recurring obligations during the next year and beyond.

Overviewof 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 and newly acquired properties.

We have received numerous inquiries regarding the possibility of funding our efforts through equity contributions or debt instruments.  Given strong cash flows, and the relatively modest nature of our current drilling projects, 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, it is possible we would consider alternative forms of additional financing.

Hedging.  During the nine months ended December 31, 2011 and 2010, we did not participate in any hedging activities, nor did we have any open futures or option contracts. 

Working Capital. At December 31, 2011, we had a working capital surplus of $3,496,000 (a current ratio of 2.56:1) compared to a working capital surplus at March 31, 2011 of $4,930,000 (a current ratio of 3.96:1).  The decline in current ratio is largely a result of greater investments in oil and gas property partially offset by the increase in income from operations.

Cash Flow. Net cash provided in operating activities was $3,084,000 for the nine months ended December 31, 2011, compared to net cash provided by operating activities of $2,412,000 for the nine months ended December 31, 2010.  Changes in operating cash relate primarily to the $1,369,000 increase in net income adjusted for non-cash expenses for the nine months ended December 31, 2011 compared to the same period ended December 31, 2011.  The fluctuation in deferred income tax expense, the timing and payment of accounts payable and accrued 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.    

Net cash used in investing activities for the nine months ended December 31, 2011, was $4,759,000, compared to $3,163,000 for the nine months ended December 31, 2010, due to an increase in the number of wells drilled and completed during the 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.  The timing of payments for these expenditures and those accrued at the respective prior year end is reflected in net cash used in investing activities for the respective nine month periods.

Net cash used in financing activities was $84,000 for the nine months ended December 31, 2011, and $107,000 for the nine months ended December 31, 2010, for the purchase of treasury shares.

11

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 statement of cash flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.

During the nine months ended December 31, 2011, we spent $5,427,000 on various projects.  This compares to $2,436,000 for the nine months ended December 31, 2010.  During the nine months ended December 31, 2011, 81% of our capital expenditures were dedicated to drilling and completing new wells and improving several older wells, 11% was deployed on leasehold and acquisitions, and 8% of capital spending dollars was spent converting certain former oil producing wells in Williston to salt water disposal wells.  All projects were funded entirely with internally generated cash flow.   

As of December 31, 2011, we have outstanding Authorizations for Expenditure (“AFEs”) above our recorded costs totaling $407,000 for our share in un-incurred drilling and completion costs of three wells in the Williston Basin.  At present cash flow levels, we expect to have sufficient funds available for our share of both the outstanding AFEs and any additional acreage, seismic and/or drilling cost requirements that might arise from our existing opportunities.  We may alter or vary all or part of any planned capital expenditures for reasons including, but not limited to changes in circumstances, unforeseen opportunities, the inability to negotiate favorable acquisition, farmout, joint venture or divestiture terms, commodity prices, lack of cash flow, and lack of additional funding.

Contemplated Activities

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

The financial statements for the nine months ended December 31, 2011 reflect the divestiture and sale of the Company’s working and/or override interests in one well.

Other Commitments

Other than the aforementioned outstanding AFEs, we do not have any other commitments beyond our office lease and software maintenance contracts.  See further detail in the notes to the unaudited condensed consolidated financial statements.

Impact of Inflation and Pricing

We deal primarily in U.S. dollars.  Inflation has not had a material impact on the Company 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.  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, and may affect our ability to raise capital or borrow money.

Reserves

During the nine months ended December 31, 2011, the present value of estimated future cash flows from proved reserves, before income taxes, discounted at 10% (“PV-10”) increased 32% from March 31, 2011; from $20,032,664 to $26,493,150.  This PV-10 reflects the favorable impact of both newly developed reserves and an increase in oil price estimates developed in conformance with SEC price guidelines.  Not reflected in this reserve increase are potential reserves for twenty-seven wells, seventeen of which are mentioned above, for which insufficient data exists on which to prepare a reliable reserve estimates, as such production data has not yet been disclosed by the operator or the state regulatory agencies.  On a BOE basis, with these twenty-seven wells not included, proved reserves in barrels of oil equivalent (“BOE”) were 1,250,139 and 1,137,064 at December 31, 2011 versus March 31, 2011, respectively.

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Results of Operations

The following provides selected financial information and averages for the three and nine months ended December 31, 2011 and 2010.

	Three Months Ended				Nine months Ended
	December 31,				December 31,
	2011		2010		2011		2010
Revenue
Oil	$	3,409,000	$	1,617,000	$	7,781,000	$	4,836,000
Gas		421,000		329,000		1,034,000		843,000
Total revenue1		3,830,000		1,946,000		8,815,000		5,679,000
Total production expense 2		1,333,000		874,000		3,292,000		2,265,000
Gross profit	$	2,497,000	$	1,072,000	$	5,523,000	$	3,414,000
Depletion expense	$	350,000	$	264,000	$	752,000	$	813,000
Sales volume
Oil (Bbls)		38,809		21,865		86,427		69,214
Gas (Mcfs) 3		63,281		50,653		140,943		122,543
Average sales price 4
Oil (per Bbl)	$	87.84	$	73.96	$	90.03	$	69.87
Gas (per Mcf)	$	6.65	$	6.50	$	7.34	$	6.88
Average per BOE 5
Production expense 3, 4	$	27.01	$	28.84	$	29.95	$	25.27
Gross profit 4	$	50.59	$	36.36	$	50.25	$	38.09
Depletion expense 4	$	7.09	$	8.96	$	6.84	$	9.07

1	Amount does not include water service and disposal revenue.  For the three and nine months ended December 31, 2011, this revenue amount is net of $36,000 and $121,000, respectively, in well service and water disposal revenue, which would otherwise total $3,866,000 and $8,936,000, respectively, in revenue, compared to $41,000 and $69,000 in the respective periods ended December 31, 2010 to total $1,987,000 and $5,748,000 for the comparable three and nine month periods ended December 31, 2010.
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
5	Per equivalent barrel (6 thousand cubic feet, “Mcf”, of gas is equivalent to 1 barrel, “Bbl”, of oil)

Overview.  Net income for the three months ended December 31, 2011, was $1,152,000 compared to net income of $74,000 for the three months ended December 31, 2010, a fifteen-fold increase.  Net income for the nine months ended December 31, 2011, compared to the nine months ended December 31, 2010, more than doubled from $1,176,000 to $2,545,000.  The rise in net income resulted from revenues having nearly doubled for the three month period offset by a 40% increase in expenses for the three month period.  Similarly, for the respective nine month periods, revenues rose 55% and were offset by a 30% escalation in expenses.

Revenues.  Oil sales revenue more than doubled for the three months ended December 31, 2011, from $1,617,000 compared to $3,409,000 for the three months ended December 31, 2010, due to a higher realized price per barrel and increase in reported production as described in “Volumes and Prices” below.

Similarly, we experienced growth of 61% on oil revenues from $4,836,000 for the nine months ended December 31, 2010, to $7,781,000 for the nine months ended December 31, 2011.

Gas sales revenue increased $92,000 (28%) and $191,000 (23%), respectively, for the three and nine months ended December 31, 2011, compared to the three and nine months ended December 31, 2010, as a result of jump in production coupled with the sharp rise in the price per Mcf.

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Volumes and Prices.  Oil sales volumes rose by 77% and 25% for the three and nine months ended December 31, 2011, compared to the three and nine months ended December 31, 2010, respectively.  The 19% and 29% increase in average price per barrel for the respective periods also positively affected oil revenues.

The large rise in oil sales volumes for the three months ended December 31, 2011, compared to the three months ended December 31, 2010 was the result of a significant contribution from new producing oil wells in North Dakota for the quarter just ended in addition to production volumes from these wells for the two prior quarters. Volume and revenue true-ups of accruals at prior quarter-end were reported in the current quarter results for a number of new producing oil wells for which production data had yet to be disclosed by the operator or the state regulatory agencies at prior quarter-end.

The upsurge in productivity of our gas wells (25% and 15% for the three and nine months ended December 31, 2011, compared to the respective periods in the prior year) were the primarily driver of the bump in gas sales revenue.  The 2% and 7% gains in average price per Mcf for the three and nine months ended December 31, 2011, compared to the respective periods in the prior year contributed to the remaining increase in revenue from natural gas sales.

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

	Three Months Ended December 31,				Nine months Ended December 31,
		2011		2010		2011		2010
Lease operating costs	$	601,000	$	464,000	$	1,678,000	$	1,283,000
Workover costs		304,000		243,000		665,000		452,000
Production taxes		350,000		130,000		688,000		403,000
Transportation and other costs		78,000		37,000		261,000		127,000
Total production expense	$	1,333,000	$	874,000	$	3,292,000	$	2,265,000

Oil and gas production expense increased $459,000 (53%) and $1,027,000 (45%) for the three and nine months ended December 31, 2011, respectively, over the expenses for the three and nine months ended December 31, 2010, largely associated with the increase in wells coupled with greater workover operations in the current periods.

Routine lease operating expense (“LOE”), consisting of lease operating costs, transportation and other costs, per BOE was $13.76 for the three months ended December 31, 2011, compared to $16.99 for the three months ended December 31, 2010, which is reflective of the spreading of costs over greater volumes.

While the higher volume is indicative of added production for new wells, in part, it is due to the aforementioned lag in reporting of volumes by the state authorities concerning newly producing wells, in that accrued volumes and revenues at prior quarter-end were trued-up in the current quarter.  As such, LOE as a percentage of sales volumes may not be representative of future results.  

A shift from the three month comparative period results, routine LOE per BOE for the nine months ended December 31, 2011, compared to the nine months ended December 31, 2010, was up 12% to $17.64 from $15.73.  This reversal compared to the three month period is not unexpected, considering that service companies are escalating their rates in response to escalating fuel and employee costs, especially in the Williston Basin, as well as in response to higher oil prices.

As a percent of oil and gas sales revenue, routine LOE was 18% and 22% for the three and nine months ended December 31, 2011, respectively, compared to 26% and 25%, for the respective three and nine months ended December 31, 2010.  This favorable movement in cost in proportion to revenue reflects the affect of oil and gas prices on revenues – while cost per unit of production increased, cost per dollar of production decreased.

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.  Workover expense increased $61,000 (25%) and $213,000 (47%) for the three and nine months ended December 31, 2011, respectively, compared to the respective period ended December 31, 2010.  Workover costs in 2011, at $6.05 per BOE, represented an investment in nineteen wells versus eleven wells in respective prior year period, when the costs totaled $5.04 per BOE.

Production taxes increased significantly by 169% and 71% for the three and nine months ended December 31, 2011, respectively, compared to the respective three and nine months ended December 31, 2010, due to increased production volumes and increased commodity prices.  More predictably, as a percent of oil and gas sales revenue, production taxes rose to 9% from 7% for the respective three month periods, and to 8% from 7% for the respective nine month periods.  Production taxes are primarily based on the wellhead values of production, though normal fluctuations occur in the percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, changes in the assessed values of oil and gas properties and equipment for purposes of ad valorem taxes, and changes in the proportion of our production between states and counties.  Because production tax rates vary from state to state, as well as across the various counties within a given 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.

In spreading costs to greater reported volumes, as noted above, overall lifting costs (oil and gas production costs, including production taxes as well as workovers) per BOE for the three months ended December 31, 2011, compared to the three months ended December 31, 2010, dropped from $29.65 to $27.01.  Similarly to the trends discussed above, wherein the relationship between costs and revenues has been less favorable for the nine months ended December 31, 2011 compared to the respective period in 2010, overall lifting costs jumped to $29.95 from $25.27.  Due to the timing of production volume reporting by state oil and gas boards, sales volume amounts may not be indicative of actual production or future performance; such should be considered upon reliance on any metric whose denominator is related to sales volumes.

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Other Expenses.

Depletion and depreciation increased $89,000 (32%) for the three months ended December 31, 2011, compared to the three months ended December 31, 2010, and decreased $54,000 (6%) for the nine months ended December 31, 2011, compared to the nine months ended December 31, 2010.  The fluctuation was driven by BOE production in relation to proved reserves coupled with non-depletable property balances.

General & Administrative (“G&A”) expense increased $81,000 (21%) and $314,000 (28%), respectively, for the three and nine months ended December 31, 2011, over the expense for the three and nine months ended December 31, 2010.  This rise in costs is comprised primarily of compensation-related expenses, which account for $94,000 and $273,000, respectively, of the increase due to the increase in number of employees, an additional Board member, and additional contract labor and consultants.  Public company expenses fell $2,000 for the three month period and rose $55,000 for the nine month period.

Although we experienced an escalation in G&A costs, the expense per BOE decreased from $13.30 for the three months ended December 31, 2010, to $9.58 for the three months ended December 31, 2011 due to greater reported production volumes over the respective quarter period in the prior year, as explained above.  For the nine month period, the G&A expense per BOE increased from $12.36 for the nine months ended December 31, 2010, to $12.94 for the nine months ended December 31, 2011, following the trend discussed above concerning the timing of reporting of sales volumes. In proportion to total revenue, G&A expense fell to 12% from 20% for the three months period and to 16% from 19% for the nine month period corresponding with the growth in sales revenue.

Income Tax.  For the three and nine months ended December 31, 2011, we recorded income tax expense of $503,000 and $823,000, respectively, as compared to $297,000 and $200,000 for the three and nine months ended December 31, 2010.  Our effective income tax rate was 30% and 24%, respectively, for the three and nine months ended December 31, 2011.  The overall effective tax rate expressed as a percentage of book income before income tax for the nine months ended December 31, 2011, as compared to the same period in 2010, was higher due primarily to true-up adjustments from amounts originally estimated on the prior year tax provisions in connection with the finalization of the tax returns..  

Subsequent Event.  On January 31, 2012, we completed the divestiture and sale of the Company’s working and/or override interests in 38 wells in Weld County, Colorado to an unrelated third party for $5,900,000. After customary post-closing adjustments and expenses, the net proceeds from the transaction are expected to be $5,300,000. The adjusted purchase price was impacted by commissions, sales costs and post effective date revenue and expense modifications to the purchase price.  The wells were considered non-core properties for the Company, given our focus on other areas, primarily the Williston Basin.

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, 2011.  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, 2011, 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.

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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

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

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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 (Jim Poage, 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 (Jim Poage, Interim Chief Financial Officer).
101	The following materials from the Company’s quarterly report on Form 10-Q for the quarter ended December 31, 2011, 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.

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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 10, 2012	By:	/s/ Ray Singleton
		Ray Singleton
		President and Chief Executive Officer
	By:	/s/ Jim Poage
		Jim Poage
		Interim Chief Financial Officer

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