EARTHSTONE ENERGY INC - Quarter Report: 2010 December (Form 10-Q)

e10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended December 31, 2010

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 (State of Incorporation or Organization)	84-0592823 (I.R.S. Employer Identification No.)
633 17th Street, Suite 1645, Denver, Colorado (Address of principal executive office)	80202-3625 (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 o 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 (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 14, 2011: 1,706,543

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EARTHSTONE ENERGY, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION	Page

Item 1.	Financial Statements	4

	Consolidated Balance Sheets:
	December 31, 2010 (Unaudited) and March 31, 2010	4

	Consolidated Statements of Operations:
	Three and Nine Months Ended December 31, 2010 and 2009 (Unaudited)	6

	Consolidated Statements of Cash Flows:
	Nine Months Ended December 31, 2010 and 2009 (Unaudited)	7

	Notes to Unaudited Consolidated Financial Statements:
	December 31, 2010 (Unaudited)	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	17

Item 4.	Controls and Procedures	17

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	18

Item 1A.	Risk Factors	18

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	18

Item 3.	Defaults Upon Senior Securities	18

Item 4.	(Removed and Reserved)	18

Item 5.	Other Information	18

Item 6.	Exhibits	19

	Signatures	20

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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. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "plan," "should" or similar expressions are intended to identify such statements. Forward-looking statements relate to, among other things:

• our future financial position, including anticipated liquidity;

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

• amounts and nature of future capital expenditures;

• acquisitions and other business opportunities;

• operating costs and other expenses;

• wells expected to be drilled;

• asset retirement obligations;

• estimates of proved oil and natural gas reserves, deferred tax liabilities, and depletion rates; and

• our ability to meet additional acreage, seismic and/or drilling cost requirements arising from acquisition opportunities.

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

• oil and natural gas prices;

• our ability to replace oil and natural gas reserves;

• loss of senior management or technical personnel;

• inaccuracy in reserve estimates and expected production rates;

• exploitation, development and exploration results;

• the actual costs related to asset retirement obligations, and whether or not those retirements actually occur in the future;

• a lack of available capital and financing;

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

• the existence of unanticipated liabilities or problems relating to acquired properties;

• general economic, market or business conditions;

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

• permitting issues, workovers, and weather;

• the impact and costs related to compliance with or changes in laws or regulations governing our oil and natural gas operations;

• environmental liabilities;

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

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

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

census; and

• other factors, many of which are beyond our control.

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 the 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.

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Earthstone Energy, Inc.

Consolidated Balance Sheets

Page 1 of 2

	December 31,			March 31,
	2010			2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	4,047,000		$	4,905,000
Accounts receivable:
Oil and gas sales		1,185,000			1,021,000
Joint interest and other receivables, net of $79,000 and $86,000 in allowance, respectively		208,000			401,000
Other current assets		604,000			732,000

Total current assets		6,044,000			7,059,000

Oil and gas property, full cost method:
Proved property		35,048,000			33,915,000
Unproved property		3,145,000			1,555,000
Accumulated depletion and impairment		(24,395,000	)		(23,582,000	)

Net oil and gas property		13,798,000			11,888,000

Support equipment and other non-current assets, net of $377,000 and $374,000 in accumulated depreciation, respectively		471,000			451,000

Total non-current assets		14,269,000			12,339,000

Total assets	$	20,313,000		$	19,398,000

See accompanying notes to unaudited consolidated financial statements.

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Earthstone Energy, Inc.

Consolidated Balance Sheets

Page 2 of 2

	December 31,			March 31,
	2010			2010
	(Unaudited)
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	333,000		$	161,000
Accrued liabilities		1,340,000			1,836,000

Total current liabilities		1,673,000			1,997,000

Long-term liabilities:
Deferred tax liability		2,295,000			2,217,000
Asset retirement obligation		1,709,000			1,674,000

Total long-term liabilities		4,004,000			3,891,000

Total liabilities		5,677,000			5,888,000

Shareholders’ Equity:
Preferred stock, $.001 par value, 600,000 authorized and none issued or outstanding		—			—
Common stock, $.001 par value, 6,400,000 shares authorized and 1,782,000 and 1,773,000 shares issued and outstanding, respectively		18,000			18,000
Additional paid-in capital		23,002,000			22,945,000
Treasury stock (75,000 and 65,000 shares, respectively); at cost		(358,000	)		(251,000	)
Accumulated deficit		(8,026,000	)		(9,202,000	)

Total shareholders’ equity		14,636,000			13,510,000

Total liabilities and shareholders’ equity	$	20,313,000		$	19,398,000

See accompanying notes to unaudited consolidated financial statements.

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Earthstone Energy, Inc.

Consolidated Statements of Operations

(Unaudited)

	Nine Months Ended						Three Months Ended
	December 31,						December 31,
	2010			2009			2010			2009

Revenues:
Oil and gas sales	$	5,679,000		$	5,487,000		$	1,946,000		$	2,017,000
Well service and water disposal revenue		69,000			39,000			41,000			12,000

Total revenues		5,748,000			5,526,000			1,987,000			2,029,000

Expenses:
Oil and gas production		1,862,000			1,758,000			744,000			738,000
Production tax		403,000			385,000			130,000		—
Well servicing expenses		6,000			39,000			3,000			13,000
Depreciation and depletion		842,000			952,000			274,000			378,000
Accretion of asset retirement obligation		124,000			124,000			43,000			41,000
Asset retirement expense		5,000			4,000		—			—
General and administrative		1,108,000			1,353,000			392,000			526,000

Total expenses		4,350,000			4,615,000			1,586,000			1,696,000

Income from operations		1,398,000			911,000			401,000			333,000

Other income (expense):
Interest and other income		11,000			63,000			3,000			13,000
Interest and other expenses		(33,000	)		(22,000	)		(33,000	)		(3,000	)

Total other income (expense)		(22,000	)		41,000			(30,000	)		10,000

Income before income taxes		1,376,000			952,000			371,000			343,000

Current income tax expense (benefit)		88,000			6,000			(11,000	)		(55,000	)
Deferred income tax expense		112,000			130,000			308,000			102,000

Total income tax expense		200,000			136,000			297,000			47,000

Net income	$	1,176,000		$	816,000		$	74,000		$	296,000

Per share amounts:
Basic	$	0.69		$	0.47		$	0.04		$	0.17
Diluted	$	0.69		$	0.47		$	0.04		$	0.17

Weighted average common shares outstanding:
Basic		1,699,877			1,734,269			1,697,097			1,723,458
Diluted		1,699,877			1,734,269			1,697,097			1,723,458

See accompanying notes to unaudited consolidated financial statements.

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Earthstone Energy, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	December 31,
	2010			2009

Cash flows from operating activities:
Net income	$	1,176,000		$	816,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		842,000			952,000
Deferred tax expense		112,000			129,000
Accretion of asset retirement obligation		124,000			124,000
Share based compensation		57,000			54,000
Change in:
Accounts receivable, net		29,000			404,000
Other current assets		128,000			(82,000	)
Accounts payable and accrued liabilities		(56,000	)		200,000

Net cash provided by operating activities		2,412,000			2,597,000

Cash flows from investing activities:
Oil and gas property		(3,114,000	)		(1,402,000	)
Support equipment		(49,000	)		(33,000	)

Net cash used in investing activities		(3,163,000	)		(1,435,000	)

Cash flows from financing activities:
Purchase of treasury shares		(107,000	)		(198,000	)

Net cash used in financing activities		(107,000	)		(198,000	)

Cash and cash equivalents:
Increase (decrease) in cash and cash equivalents		(858,000	)		964,000
Balance, beginning of year		4,905,000			4,088,000

Balance, end of period	$	4,047,000		$	5,052,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	—		$	16,000
Cash paid for income tax	$	214,000		$	25,000
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	261,000		$	31,000
Vested shares issued as compensation	$	—		$	48,000
Additions to oil and gas also included in accrued liabilities	$	296,000		$	568,000

See accompanying notes to unaudited consolidated financial statements.

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Earthstone Energy, Inc.

Notes to Unaudited Consolidated Financial Statements

December 31, 2010

1. Presentation of Consolidated Financial Statements

The accompanying interim consolidated financial statements of Earthstone Energy, Inc. (formerly Basic Earth Science Systems, Inc. sometimes referred to as “the Company” “we” “our” or “us”) are unaudited. However, in the opinion of management, the interim data includes any applicable adjustments necessary for a fair presentation according to generally accepted accounting principles (GAAP) of the financial and operational results for the interim period.

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. When such terms are used in this manner throughout this document 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 footnote disclosures normally included in financial statements prepared in accordance with 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 our Annual Report on Form 10-K for the year ended March 31, 2010.

For the period ended December 31, 2010, we determined that there were no subsequent events to recognize or disclose in these consolidated financial statements which would either impact the results reflected in this report or the Company’s results going forward.

Organization and Nature of Operations. Earthstone Energy, Inc. was originally organized in July 1969 as Basic Earth Science Systems, Inc. We are principally engaged in the acquisition, exploitation, development, operation and production of crude oil and natural gas. Our primary areas of operation are the Williston basin in North Dakota and Montana, south Texas and the Denver-Julesburg basin in Colorado.

Principles of Consolidation. The consolidated financial statements include our accounts and those of our wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. The Company does not have any off-balance sheet financing arrangements or any unconsolidated special purpose entities.

2. Summary of Significant Accounting Policies and Recent Accounting Pronouncements

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the actual amounts of assets and liabilities at the date of the financial statements and the actual amounts of revenues and expenses during the reporting period. We base these estimates on assumptions that we understand are reasonable under the circumstances. The estimated results that are produced by this effort will differ under different assumptions or conditions. We understand that these estimates are necessary, and we caution that actual results could vary significantly from the estimated amounts for the current and future periods.

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There are many factors, including global events, which may influence the production, processing, marketing, and valuation of crude oil and natural gas. A reduction in the valuation of oil and gas properties resulting from declining prices or production could adversely impact depletion rates and ceiling test limitations. We understand the following accounting policies and estimates are necessary in the preparation of our consolidated financial statements: the carrying value of our oil and gas property, the accounting for oil and gas reserves, the estimate of our asset retirement obligations, the estimate of our income tax assets and liabilities and estimates of accrued quantities and prices in our oil and gas receivable.

Oil and Gas Reserves. Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. As of our year end, March 31, 2010, ninety-three percent of our reported oil and gas reserves are based on estimates prepared by Ryder Scott Company, L.P, a nationally recognized, independent petroleum engineering firm. The remaining seven percent of our oil and gas reserves were prepared by our technical in-house staff.

Oil and Gas Sales. We derive revenue primarily from the sale of produced natural gas and crude oil. We report revenue on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between 30 and 90 days after the date of production. We make estimates of the amount of production delivered to purchasers and the prices we will receive. We use our knowledge of our properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received, or when better information is available.

Oil and Gas Property. We follow the full cost method of accounting for our oil and gas property. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or fair value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts stockholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. As of the balance sheet date, our capitalized costs did not exceed the ceiling test limit.

Cash and Cash Equivalents. For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, we consider all highly liquid investments with a maturity of ninety days or less when purchased to be cash equivalents. The carrying amount of cash equivalents approximates fair value because of the short-term maturity of those instruments. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.

Support Equipment and Other. Support equipment (including such items as vehicles, office furniture and equipment and well servicing equipment) is stated at cost. Depreciation of support equipment and other property is computed using the straight-line method over periods ranging from five to seven years.

Long-Lived Assets. We regularly evaluate all long-lived assets for possible impairment. Assets are reported at the lower of cost or their estimated recoverable amounts. During the periods ended December 31, 2010 and 2009 there was no impairment recorded for long-lived assets.

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Fair Value Measurements. Effective April 1, 2009, we adopted the provisions for nonfinancial assets and liabilities that are not required to be measured at fair value on a recurring basis, which include, among others, those assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. Accordingly, the fair value is based on unobservable pricing inputs and therefore, is considered a level 3 value input in the fair value hierarchy.

Asset Retirement Obligations. We have obligations related to the plugging and abandonment of our oil and gas wells. We estimate the future cost of these obligations, discount this cost to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on numerous and significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash expenditures and inflation rates. The nature of these estimates requires us to make judgments based on historical experience and future expectations related to timing. We review the estimate of our future asset retirement obligations quarterly. These quarterly reviews may require revisions to these estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis.

We recognize two components on our Consolidated Statement of Operations; accretion of asset retirement obligations and asset retirement expense. Accretion of asset retirement obligation reflects the periodic accretion of the present value of future plugging and abandonment costs. Asset retirement expense reflects the actual current period gains and losses on plugging and abandonment costs relative to previously estimated future costs. We have closed gains and losses on asset retirements to the Consolidated Statement of Operations as a component of asset retirement expense.

The information below reconciles the value of the asset retirement obligation for the period presented. This includes a short term obligation of $186,000 for December 31, 2010, which is carried within the accrued liabilities line item of the balance sheet.

	Nine Months Ended						Three Months Ended
	December 31,						December 31,
	2010			2009			2010			2009

Balance beginning of period	$	1,774,000		$	1,698,000		$	1,859,000		$	1,643,000
Liabilities incurred		48,000			16,000			78,000			—
Liabilities settled		(264,000	)		(107,000	)		(78,000	)		—
Revisions to estimates		213,000			(47,000	)		(7,000	)		—
Accretion expense		124,000			124,000			43,000			41,000

Balance end of period	$	1,895,000		$	1,684,000		$	1,895,000		$	1,684,000

Commitments. We currently office in a 4,000 square foot office space located in downtown Denver, Colorado, and are committed to a total of $281,000 plus maintenance fees for the five-year lease term ending April 1, 2013. We have no off balance sheet transactions or arrangements.

Income Taxes. We account for income taxes with deferred tax liabilities and assets which are determined based on the temporary differences between the financial statements and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse.

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Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, the net deferred tax liability is continually re-evaluated and numerous estimates are revised over time. As such, the net deferred tax liability 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.

We are 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 fiscal years 2007 through 2009. We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2010, we made no provisions for interest or penalties related to uncertain tax positions.

Reverse Stock Split. Effective December 31, 2010, the Board of Directors authorized and effected a 1-for-10 reverse stock split which converted ten (10) shares of the Company’s common stock into one (1) share of common stock. The Board of Directors also authorized and effected a 1-for-5 reverse stock split for the number of authorized common shares and preferred shares as follows; (a) the reduction of the number of authorized shares of common stock from the then authorized 32,000,000 shares down to 6,400,000 shares, and (b) the reduction of the number of authorized shares of preferred stock from the then authorized 3,000,000 shares down to 600,000 shares. Both the common and preferred shares maintain a par value of $0.001. All references to the number of common shares issued in the accompanying consolidated financial statements reflect the reverse stock split.

Earnings Per Share. Our earnings per share (EPS) is computed by dividing net income by the weighted average number of common shares outstanding for the period, after giving effect to the 1-for-10 reverse stock split effective December 31, 2010. Diluted EPS is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options. As of the balance sheet date, no dilutive securities were outstanding.

Reclassifications. Certain prior year amounts were reclassified to conform to current year presentation. Such reclassifications had no effect on net income.

Recent Accounting Pronouncements

In January 2010, guidance for fair value measurements and disclosure was updated to require additional disclosures related to transfers in and out of level 1 and 2 fair value measurements and enhanced detail in the level 3 reconciliation. The guidance was amended to clarify the level of disaggregation required for assets and liabilities and the disclosures required for inputs and valuation techniques used to measure the fair value of assets and liabilities that fall in either level 2 or level 3. The updated guidance was effective for the Company’s fiscal year beginning April 1, 2010, with the exception of the level 3 disaggregation which is effective for the Company’s fiscal year beginning April 1, 2011. With the exception of the of level 3 disaggregation, which has not yet been adopted, the adoption of this guidance is not expected to impact the Company’s consolidated financial position, results of operations or cash flows.

In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements is a broader definition of reserves, which allows reporting of probable and possible reserves, in addition to consideration of new technologies and non-traditional resources. In addition, oil and gas reserves will be reported using an average price based on the first-day-of-the-month price during the prior 12-month period, rather than year-end prices. The new rules are effective for years ending on or after December 31, 2009. The adoption of the new rules is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or financial statements which also impact the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new guidance, subsequent price increases cannot be considered in the ceiling test calculation. The Company does not believe that it is practicable to estimate the effect of applying the new rules on net loss or the amounts recorded for depreciation, depletion and amortization and ceiling impairment.

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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 fiscal year ended March 31, 2010, as well as the financial statements and related notes and other information appearing elsewhere in this report.

As a crude 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 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, will enable us to meet our existing and normal recurring obligations during the next year and beyond.

Working Capital. At December 31, 2010, we had a working capital surplus of $4,371,000 (a current ratio of 3.61:1) compared to a working capital surplus at March 31, 2010 of $5,062,000 (a current ratio of 3.53:1). The increase in current ratio is primarily a result of the timing between payments made for payables, cash received for revenue and joint interest billings and the timing and use of prepaid balances.

Cash Flow. Net cash provided by operating activities decreased 7.1% from $2,597,000 in the nine months ended December 31, 2009 (“2009”) to $2,412,000 in the nine months ended December 31, 2010 (“2010”). This change related primarily to the timing and collection of accounts receivable, the timing and payment of accounts payable and accrued liabilities, and the application of prepaid balances.

Net cash used in investing activities increased 120.4% from $1,435,000 in the nine months ended December 31, 2009 to $3,163,000 in the nine months ended December 31, 2010. The difference relates primarily to expenditures made during 2010 on an acquisition of producing properties, new horizontal Bakken wells in the Williston Basin, the recompletion of DJ Basin wells in Colorado and on additional acreage.

Net cash used in financing activities decreased 46.0% from $198,000 in the nine months ended December 31, 2010 to $107,000 in the nine months ended December 31, 2010. The decrease was associated with the Company’s stock buyback program, adopted in October 2008, and occurred because fewer shares were purchased during 2010 compared to 2009.

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Credit Line. Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Subject to evaluation every six months, a line of credit amount was set at $20 million with a concurrent borrowing base of $4 million. Effective December 31, 2008, the loan agreement was amended to extend the maturity date of the credit agreement to December 31, 2010. The extended agreement provided for an interest rate of prime plus 0.25% or 6.5% whichever was higher. The line could be used for purposes of borrowing funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities that might arise. The loan contained several covenant restrictions. At December 31, 2010, we were in compliance with all covenants, but had not yet renewed the credit line.

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 Consolidated Statement of Cash Flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.

During the quarter ended December 31, 2010, we spent approximately $1,486,000 on various projects. This compares to $1,354,000 for the quarter ended December 31, 2009. During the quarter ended December 31, 2010, capital expenditures were comprised of acquisitions (51.6%), drilling and completions (28.2%) and leasehold (20.2%). The purchase of five producing wells in the Outlook Field of Sheridan County, Montana accounted for nearly all acquisition expenditures. Approximately 92.9% of drilling and completion expenditures, were spent in the Montana and North Dakota portions of the Williston Basin and 5.9% in the DJ Basin.

At present cash levels, we expect to have sufficient funds available for our share of any additional acreage, seismic and/or drilling cost requirements that might arise from these 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 or joint venture terms, lack of cash flow and lack of additional funding.

We currently have no capital expenditure commitments. We are continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of due diligence. 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

During the quarter ended December 31, 2010, we plugged four wells.

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Results of Operations

Overview. Net income for the three and nine months ended December 31, 2010 was $74,000 and $1,176,000, compared to net income of $296,000 and $816,000 for the three and nine months ended December 31, 2009. The following table shows selected financial information for the three and nine months ended December 31 in the current and prior year. Certain prior year amounts may have been reclassified to conform to current year presentation.

		Nine Months Ended				Three Months Ended
		December 31,				December 31,
		2010		2009		2010		2009

Sales volume
Oil (barrels)		69,214		80,215		21,865		28,606
Gas (mcf) (1)		122,543		197,192		50,653		77,866

Revenue
Oil	$	4,836,000	$	4,824,000	$	1,617,000	$	1,843,000
Gas		843,000		663,000		329,000		174,000
Total revenue (2)		5,679,000		5,487,000		1,946,000		2,017,000

Total production expense (3)		2,265,000		2,143,000		874,000		738,000

Gross profit	$	3,414,000	$	3,344,000	$	1,072,000	$	1,279,000

Depletion expense	$	813,000	$	924,000	$	264,000	$	368,000

Average sales price (4)
Oil (per barrel)	$	69.87	$	60.14	$	73.96	$	64.43
Gas (per mcf)	$	6.88	$	3.36	$	6.50	$	2.23

Average per BOE
Production expense (3,4,5)	$	25.27	$	18.95	$	29.65	$	17.75
Gross profit (4,5)	$	38.09	$	29.57	$	36.36	$	30.76
Depletion expense (4,5)	$	9.07	$	8.17	$	8.96	$	8.85

(1)	Due to the timing and accuracy of sales information received from a third party operator as described in “Volumes and Prices” below, sales volume amounts may not be indicative of actual production or future performance.
(2)	Amount does not include water service and disposal revenue. For the three and nine months ended December 31, 2010 this revenue amount is net of $41,000 and $69,000, respectively in water service and disposal revenue, which would otherwise total $1,987,000 and $5,748,000 in revenue respectively, compared to $12,000 and $39,000, respectively in 2009 to total $2,029,000 and $5,526,000, respectively for the same period in 2009.
(3)	Overall lifting cost (oil and gas production expenses and production taxes)
(4)	Averages calculated based upon non-rounded volumes
(5)	Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

Revenues. Oil and gas sales revenue decreased $71,000 (3.5%) in 2010 from 2009 due to decreased volumes on a barrel of oil equivalent (BOE) basis, which were partially offset by higher realized oil and gas prices. Oil sales revenue decreased $226,000 (12.3%), and gas sales revenue increased $155,000 (89.1%) in 2010 from 2009.

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Volumes and Prices. Oil sales volume decreased 23.6%, from 28,606 barrels in 2009 to 21,865 barrels in 2010. This decrease was primarily related to production declines on two wells; the Halvorsen 31x-36 in the Williston basin and the USA 4-36 in the DJ basin. These two wells, both newly drilled in 2009, contributed high initial production in 2009. As anticipated, in 2010, these two wells exhibited steep, but normal initial declines; thereby reducing oil sales by approximately 5,600 barrels from 2009. To a lesser extent, for the reasons detailed in the paragraph below, oil volumes in the DJ basin reported in our December 2009 Form 10-Q were not representative of normal oil sales. Oil sales from these wells were approximately 1,200 barrels higher than actual volumes sold in the period. The average price per barrel increased 14.8%, from $64.43 in 2009 to $73.96 in 2010.

Gas sales volume decreased 34.9% from 77,866 thousand cubic feet (Mcf) in 2009 to 50,653 Mcf in 2010. This apparent decline was created because 2009 gas volume was not representative of normal gas sales. In December 2009, we received and reported in our December 2009 Form 10-Q approximately 46,000 Mcf in gas sales that exceeded our previous accrued estimates of gas sales from periods as far back as April 2008. From April 2008 to September 2009, the operator of our DJ Basin wells was in the midst of an accounting system conversion and furnished us with minimal data. In those prior periods, we estimated and accrued gas sales based on the information available at the time. Had accurate information on gas sales been available and reported in those prior periods, we estimate that our reported gas sales volumes in our December 2009 Form 10-Q would have been approximately 32,000 Mcf; implying an increase in gas sales volumes in 2010 over 2009. This inferred increase in gas volume is attributable to six wells in the DJ basin that were deepened from the Codell formation to the J Sand formation in June 2010. The average price per Mcf increased 191.5%, from $2.23 in 2009 to $6.50 in 2010.

On an equivalent barrel of oil (BOE) basis, sales volume decreased 29.1% from 41,584 BOE in 2009 to 29,480 BOE in 2010.

Expenses. Oil and gas production expense, which includes routine lease operating expense and workover expense, increased $6,000 (0.8%) in 2010 over 2009. Workover expenses increasing by $135,000 (125.0%) from $108,000 in 2009 to $243,000 in 2010. This increase was partially offset by routine lease operating expense decreasing $129,000 (20.5%) from $630,000 in 2009 to $501,000 in 2010. Despite this decrease, routine lease operating expense per BOE increased 12.2% from $15.15 in 2009 to $16.99 in 2010 because reported BOE sales were lower in 2010, as discussed above. Workover expense per BOE also increased 217.0% from $2.60 in 2009 to $8.24 in 2010 due to increased workover operations in the Williston Basin in 2010 and because reported BOE sales were lower in 2010, as discussed above.

Reported production taxes increased $130,000 from 2009 to 2010. In 2009, having received updated information from the operator of our DJ Basin properties as discussed above, reported production taxes were reduced to resolve prior period accruals. Production taxes, as a percent of sales revenue increased from 0.0% in 2009 to 6.5% in 2010.

The overall lifting cost (oil and gas production expense and production taxes) per BOE increased 67.5% from $17.70 in 2009 to $29.65 in 2010.

Depreciation and depletion expense decreased $104,000 (28.3%) in 2010 compared to 2009 because reported BOE sales were lower in 2010, as discussed above.

General and administrative (G&A) expense decreased $134,000 (25.5%) in 2010 from 2009. This decrease was primarily due to reductions in professional fees; which included investor relations costs, legal fees, accounting fees and Sarbanes-Oxley expenses. G&A expense per BOE increased 5.1% from $12.65 in 2009 to $13.30 in 2010 because reported BOE sales were lower in 2010, as discussed above. As a percent of total sales revenue, G&A expense decreased from 25.9% in 2009 to 19.7% in 2010.

Income Tax Expense (Benefit). For the three months ended December 31, 2010 we recorded income tax expense of $297,000. This amount consists of a current period benefit of $11,000, and deferred tax expense of $308,000. Our effective income tax rate increased from 13.7% for the three months ended December 31, 2009 to 21.6% for the three months ended December 31, 2010. Our effective income tax rate was higher for the three-month period ended December 31, 2010 primarily due to a decrease in statutory depletion.

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Nine Months Ended December 31, 2010 Compared to Nine Months Ended December 31, 2009

Revenues. Oil and gas sales revenue increased $192,000 (3.5%) in the nine months ended 2010 (2010) from the nine months ended in 2009 (2009) due to higher realized oil and gas prices. Oil sales revenue increased $12,000 (0.2%), and gas sales revenue increased $180,000 (27.1%) in 2010 from 2009 due to increases in the gas price per Mcf.

Volumes and Prices. Oil sales volume decreased 13.7%, from 80,215 barrels in 2009 to 69,214 barrels in 2010. This decrease was primarily related to production declines on two wells; the Halvorsen 31x-36 in the Williston basin and the USA 4-36 in the DJ basin. These two wells, both newly drilled in 2009, contributed high initial production in 2009. As anticipated, in 2010, these two wells exhibited steep, but normal initial declines; thereby reducing oil sales by approximately 6,500 barrels from 2009. To a lesser extent, for the reasons discussed above, oil volumes in the DJ basin reported in the December 2009 Form 10-Q were not representative of normal oil sales. Oil sales from these wells were approximately 1,200 barrels higher than actual volumes sold in the period. The average price per barrel increased 16.2%, from $60.14 in 2009 to $69.87 in 2010.

Gas sales volume decreased 37.9% from 197,192 thousand cubic feet (Mcf) in 2009 to 122,543 Mcf in 2010. For the reasons discussed above, this apparent decline was created because 2009 gas volume was not representative of normal gas sales. In December 2009, we received and reported in our December 2009 Form 10-Q approximately 131,500 Mcf in gas sales that exceeded our previous accrued estimates of gas sales from periods as far back as April 2008. Had accurate information on gas sales been available and reported in those prior periods, we estimate that our reported gas sales volumes for nine months in our December 2009 Form 10-Q would have been approximately 66,000 Mcf; implying an increase in gas sales volumes in 2010 over 2009. This inferred increase in gas volume is attributable to six wells in the DJ basin that were deepened from the Codell formation to the J Sand formation in June 2010. The average price per Mcf increased 104.8%, from $3.36 in 2009 to $6.88 in 2010.

On an equivalent barrel of oil (BOE) basis, sales volume decreased 20.7% from 113,080 BOE in 2009 to 89,637 BOE in 2010.

Expenses. Oil and gas production expense, which includes routine lease operating expense and workover expense, increased $104,000 (5.9%) in 2010 over 2009, primarily due to workover expenses increasing by $172,000 (61.4%) from 280,000 in 2009 to 452,000 in 2010. This increase was partially offset by routine lease operating expense decreasing $68,000 (4.6%) from $1,478,000 in 2009 to $1,410,000 in 2010. Despite this decrease, routine lease operating expense per BOE increased 20.4% from $13.07 in 2009 to $15.73 in 2010 due to the recovering oil and gas prices, corresponding increases in operating costs and because reported BOE sales were lower in 2010, as discussed above. Workover expense per BOE also increased 103.2% from $2.48 in 2009 to $5.04 in 2010 largely due to increased workover operations in the Company’s south Texas waterflood fields during 2010 and because reported BOE sales were lower in 2010, as discussed above.

Production taxes, which are generally a percentage of sales revenue, increased $18,000 (4.7%) in 2010 compared to 2009. Production taxes, as a percent of sales revenue remained consistent at 7.0% in 2009 and 7.0% in 2010.

The overall lifting cost (oil and gas production expense and production taxes) per BOE increased 33.3% from $18.95 in 2009 to $25.27 in 2010.

Depreciation and depletion expense decreased $110,000 (11.6%) in 2010 compared to 2009 because reported BOE sales were lower in 2010, as discussed above.

General and administrative (G&A) expense decreased $245,000 (18.1%) in 2010 from 2009. The decrease primarily related to reductions in professional fees; which included investor relations costs, legal fees, accounting fees and Sarbanes-Oxley expenses. The decrease also related to reductions in shareholder related expenses and other expenses including travel and franchise tax. G&A expense per BOE increased 3.4% from $11.96 in 2009 to $12.36 in 2010. As a percent of total sales revenue, G&A expense decreased from 24.5% in 2009 to 19.3% in 2010.

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Income Tax Expense (Benefit). For the nine months ended December 31, 2010 we recorded income tax expense of $200,000. This includes current period expense of $88,000, and a deferred tax benefit of $112,000. Our effective income tax rate decreased from 14.3% for the nine months ended December 31, 2009 to 14.5% for the nine months ended December 31, 2010.

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

The Company maintains a system of disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for the purpose of providing reasonable assurance that information required to be disclosed in its SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and the Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosures.

For the quarter ended December 31, 2010, we evaluated under the supervision and with the participation of the Company’s Chief Executive Officer and Principal Accounting Officer, the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, we concluded that the Company’s disclosure controls and procedures are effective for the purposes discussed above.

There have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s quarter ended December 31, 2010 that have materially affected, or were reasonably likely to materially affect, the Company’s 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

The following table summarizes stock repurchase activity for the three months ended December 31, 2010. These shares have been adjusted for the 1-for-10 reverse stock split effective December 31, 2010.

	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Number of Shares Purchased as Part of a Publicly Announced Plan (1)		Maximum Shares that May Yet be Purchased under the Plan (1)

Oct 1, 2010 - Oct 31, 2010		1,160	$	1.09		1,160		112,155
Nov 1, 2010 - Nov 30, 2010		1,460	$	1.07		1,460		110,695
Dec 1, 2010 - Dec 31, 2010		30	$	1.14		30		110,665

Total		2,650				2,650

(1)

On October 22, 2008, the Company’s board of directors authorized a stock buyback program for the Company to repurchase up to 50,000 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. On February 10, 2010, the board extended the termination date of the program from April 22, 2010 to October 22, 2011. During the three months ended December 31, 2010, 2,650 shares were repurchased under the stock buyback program and 110,665 shares remain available for future repurchase.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

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, Chief Executive Officer).

31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting 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, 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 (Joseph Young, Principal Accounting Officer).

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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.
By: /s/ Ray Singleton
Ray Singleton
President and Chief Executive Officer

By: /s/ Joseph Young
Joseph Young
Principal Accounting Officer

Date: February 14, 2011