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, 2009

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

Commission file number: 0-7914

BASIC EARTH SCIENCE SYSTEMS, INC.

Incorporated in Delaware IRS ID# 84-0592823

633 Seventeenth St, Suite 1645

Denver, Colorado 80202-3625

Telephone (303) 296-3076

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 12, 2010: 17,070,815

1

BASIC EARTH SCIENCE SYSTEMS, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION	Page
Item 1.	Financial Statements	4
	Consolidated Balance Sheets:
	December 31, 2009 (Unaudited) and March 31, 2009	4
	Consolidated Statements of Operations:
	Three and Nine Months Ended December 31, 2009 and 2008 (Unaudited)	6
	Consolidated Statements of Cash Flows:
	Nine Months Ended December 31, 2009 and 2008 (Unaudited)	7
	Notes to Unaudited Consolidated Financial Statements:
	December 31, 2009 (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 4T.	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.	Submission of Matters to a Vote of Security Holders	18
Item 5.	Other Information	20
Item 6.	Exhibits	20
	Signatures	21

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. 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; and

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

•      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 discussed in this report and those risk factors discussed in the “Risk Factors” section of our Annual Report on Form 10-K for the

  fiscal year ended March 31, 2009.

•      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.  Disclosure of important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2009, under the heading "Risk Factors", and elsewhere in this report, including, without limitation, in conjunction with the forward-looking statements.  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.

3

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 1 of 2

	December 31,			March 31,
	2009			2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	5,052,000		$	4,088,000
Accounts receivable:
Oil and gas sales		1,104,000			1,611,000
Joint interest and other receivables, net of $71,000 and $71,000 in allowance, respectively		333,000			230,000
Other current assets		590,000			508,000
Total current assets		7,079,000			6,437,000
Oil and gas property, full cost method:
Proved property		34,291,000			32,187,000
Unproved property		775,000			1,077,000
Accumulated depletion and impairment		(23,322,000	)		(22,397,000	)
Net oil and gas property		11,744,000			10,867,000
Support equipment and other non-current assets, net of $365,000 and $337,000 in accumulated depreciation, respectively		464,000			458,000
Total non-current assets		12,208,000			11,325,000
Total assets	$	19,287,000		$	17,762,000

See accompanying notes to unaudited consolidated financial statements.

4

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 2 of 2

	December 31,			March 31,
	2009			2009
	(Unaudited)
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	381,000		$	64,000
Accrued liabilities		1,688,000			1,328,000
Total current liabilities		2,069,000			1,392,000
Long-term liabilities:
Deferred tax liability		2,371,000			2,242,000
Asset retirement obligation		1,557,000			1,558,000
Total long-term liabilities		3,928,000			3,800,000
Total liabilities		5,997,000			5,192,000
Stockholders’ Equity:
Preferred stock, $.001 par value, 3,000,000 authorized, and none issued or outstanding		—			—
Common stock, $.001 par value, 32,000,000 shares authorized, and 17,704,000 and 17,506,000 shares issued and outstanding respectively		18,000			18,000
Additional paid-in capital		22,927,000			22,825,000
Treasury stock (633,000 and 380,000 shares respectively); at cost		(241,000	)		(43,000	)
Accumulated deficit		(9,414,000	)		(10,230,000	)
Total stockholders’ equity		13,290,000			12,570,000
Total liabilities and stockholders’ equity	$	19,287,000		$	17,762,000

See accompanying notes to unaudited consolidated financial statements.

5

Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

(Unaudited)

		Nine Months Ended					Three Months Ended
		December 31,					December 31,
		2009			2008		2009		2008
Revenues:
Oil and gas sales	$	5,487,000		$	8,173,000	$	2,017,000	$	2,164,000
Well service and water disposal revenue		39,000			86,000		12,000		41,000
Total revenues		5,526,000			8,259,000		2,029,000		2,205,000
Expenses:
Oil and gas production		1,758,000			1,913,000		738,000		753,000
Production tax		385,000			618,000		―		120,000
Well servicing expenses		39,000			28,000		13,000		6,000
Depreciation and depletion		952,000			976,000		378,000		558,000
Accretion of asset retirement obligation		124,000			54,000		41,000		18,000
Asset retirement expense		4,000			164,000		―		35,000
Impairment of oil and gas properties		―			2,694,000		―		2,694,000
General and administrative		1,353,000			932,000		526,000		374,000
Total expenses		4,615,000			7,379,000		1,696,000		4,558,000
Income (loss) from operations		911,000			880,000		333,000		(2,353,000)
Other Income (Expense):
Interest and other income		63,000			54,000		13,000		12,000
Interest and other expenses		(22,000)			(27,000)		(3,000)		(11,000)
Total other income		41,000			27,000		10,000		1,000
Income (loss) before income taxes		952,000			907,000		343,000		(2,352,000)
Current income tax expense (benefit)		6,000			444,000		(55,000)		76,000
Provision for deferred income taxes		130,000			(293,000)		102,000		(858,000)
Total income tax expense (benefit)		136,000			151,000		47,000		(782,000)
Net income (loss)	$	816,000		$	756,000	$	296,000	$	(1,570,000)
Per share amounts:
Basic	$	0.05		$	0.04	$	0.02	$	(0.09)
Diluted	$	0.05		$	0.04	$	0.02	$	(0.09)
Weighted average common shares outstanding:
Basic		17,342,694	,		17,050,249		17,234,576		16,939,173
Diluted		17,342,694			17,072,196		17,234,576		16,960,961

See accompanying notes to unaudited consolidated financial statements.

6

Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

		Nine Months Ended
		December 31,
		2009		2008
Cash flows from operating activities:
Net income	$	816,000	$	756,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		952,000		976,000
Deferred tax liability		129,000		(293,000)
Accretion of asset retirement obligation		124,000		54,000
Share based compensation		54,000		24,000
Impairment of Oil and Gas Properties		―		2,694,000
Change in:
Accounts receivable, net		404,000		(115,000)
Other current assets		(82,000)		(17,000)
Accounts payable and accrued liabilities		200,000		265,000
Net cash provided by operating activities		2,597,000		4,344,000
Cash flows from investing activities:
Oil and gas property		(1,402,000)		(3,587,000)
Support equipment		(33,000)		―
Net cash used in investing activities		(1,435,000)		(3,587,000)
Cash flows from financing activities:
Purchase of treasury shares		(198,000)		(15,000)
Net cash used in financing activities		(198,000)		(15,000)
Cash and cash equivalents:
Increase in cash and cash equivalents		964,000		742,000
Balance, beginning of year		4,088,000		5,571,000
Balance, end of period	$	5,052,000	$	6,313,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	16,000	$	7,000
Cash paid for income tax	$	25,000	$	487,000
Non-cash:
Decrease (increase) in oil and gas property due to asset retirement obligation	$	31,000	$	(33,000)
Vested shares issued as compensation	$	48,000	$	24,000
Additions to oil and gas also included in accrued liabilities	$	568,000	$	263,000

See accompanying notes to unaudited consolidated financial statements.

7

Basic Earth Science Systems, Inc.

Notes to Unaudited Consolidated Financial Statements

December 31, 2009

1. Presentation of Consolidated Financial Statements

The accompanying interim financial statements of 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 of the 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 Basic Earth Science Systems, Inc.  When such terms are used in this manner throughout this document they are in reference only to the corporation, Basic Earth Science Systems, 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 generally accepted accounting principles 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, 2009 and Quarterly Reports on Form 10-Q for the quarters ended September 30, 2009 and June 30, 2009.

For the period ended December 31, 2009 through February 12, 2010, the filing date of this report, 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. Basic Earth Science Systems, Inc. was originally organized in July 1969 and had its first public offering in 1980. 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. 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.

8

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, 2009, ninety-eight 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 two percent of our oil and gas reserves were prepared by our technical in-house staff.

Each quarter, we update reserve estimates by substituting the prices we would have received at quarter-end for the year-end prices that were used by our independent petroleum engineers.  In conducting this “re-pricing” no changes are made to the decline rates, tax rates or lifting costs used by our independent petroleum engineers.  The determinations of depletion expense, as well as the results of ceiling tests and corresponding write-downs, if any, are highly dependent on these reserve and quarterly “re-pricing” estimates.

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 title changes hands. 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 using current prices and costs 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 2009 there was no impairment recorded for long-lived assets, compared to $2,694,000 for 2008.

9

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 $127,000, which is carried within the accrued liabilities line item of the balance sheet. 

	Nine Months Ended
	December 31,
	2009
Asset retirement obligation – April 1, 2009	$	1,698,000
Liabilities incurred		16,000
Liabilities settled		(107,000	)
Revisions to estimates		(47,000	)
Accretion expense		124,000
Asset retirement obligation – December 31, 2009	$	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.

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.

10

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 2006 through 2008. We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2009, we made no provisions for interest or penalties related to uncertain tax positions.

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. 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 October 2009, the Financial Accounting Standards Board (FASB) issued authoritative guidance that amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. The guidance is expected to result in more multiple-deliverable arrangements being separable than under current guidance. This guidance is effective for the Company beginning on April 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. The adoption of this guidance will not have a material impact on our consolidated financial statements or results of operations.

In June 2009, the FASB issued Accounting Standards Codification, “Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (Codification) which will become the source of authoritative U.S. generally accepted accounting principles (GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative.  This Statement is effective for financial statements issued for interim and annual periods ended after September 15, 2009.  The adoption of the Codification did not have a material impact on our consolidated financial statements or results of operations.

In June 2009, the FASB issued guidance related to subsequent events which incorporates the guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. The new guidance is effective for all interim and annual periods ended after June 15, 2009. The Company adopted the guidance upon its issuance and it had no material impact on our consolidated financial statements.

On April 29, 2009, the FASB issued guidance related to financial instruments, which requires publicly-traded companies to provide disclosures on the fair value of financial instruments in interim financial statements, and is effective for interim periods ended after June 15, 2009. We have adopted these new provisions, which did not have a material impact on the Company’s consolidated financial statements or results of operations.

On April 1, 2009, the FASB issued guidance related to business combinations, which addresses application issues associated with initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination, including the treatment of contingent consideration, acquisition costs, research and development assets and restructuring costs. In addition, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. The new guidance is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will apply the new provisions to future acquisitions.

11

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 prior 12-month period, rather than year-end prices, and allow companies to disclose their probable and possible reserves to investors. The new rules are expected to be effective for years ending on or after December 31, 2009. The Company is in the process of evaluating the effect of these new requirements, and has not yet determined the impact that it will have on its financial statements upon full adoption on March 31, 2010.

In September 2006, the FASB issued guidance related to fair value measurements and disclosures, which defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. The new guidance is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB proposed a one year deferral of the implementation for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On April 1, 2008, we adopted the new guidance with the one-year deferral for non-financial assets and liabilities. The adoption of the new guidance did not have a material impact on our financial position, results of operations or cash flows. Beginning April 1, 2009, we have adopted the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The adoption did not have a material impact on our financial statements.

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, 2009, 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. Assuming that oil prices do not decline from current levels, 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, 2009, we had a working capital surplus of $5,010,000 (a current ratio of 3.42:1) compared to a working capital surplus at March 31, 2009 of $5,045,000 (a current ratio of 4.62:1). The decrease in current ratio is largely a result of the timing between payments made for payables and cash received for revenue.

Cash Flow. Net cash provided by operating activities decreased 40.2% from $4,344,000 in the nine months ended December 31, 2008 (“2008”) to $2,597,000 in the nine months ended December 31, 2009 (“2009”) primarily due to decreased oil and gas commodity prices.   Our net income was reduced by non-cash impairment charges (for 2008) and non-cash depletion expense.

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Net cash used in investing activities decreased 60.0% from $3,587,000 in the nine months ended December 31, 2008 to $1,435,000 in the nine months ended December 31, 2009. The difference relates primarily to significantly more expenditures made during the prior year on the DJ Basin wells in Colorado.

Net cash used in financing activities increased 1,220.0% from $15,000 in the nine months ended December 31, 2008 to $198,000 in the nine months ended December 31, 2009.   Cash used in financing activities related to the stock buyback program adopted in October 2008.

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, the 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.  We renewed the line with an interest rate of prime plus 0.25% or 6.5% whichever is higher.  During the year ended March 31, 2009 and for the nine months ended December 31, 2009, we did not utilize our credit facility.  The loan contains several covenant restrictions.   At December 31, 2009, we were in compliance with all covenants.  This line may 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.

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, 2009, we spent approximately $1,354,000 on various projects.   When combined with first and second quarter investments, we have deployed $1,826,000 through the first nine months of the current fiscal year.  This compares to $353,000 and $1,568,000 for the quarter and nine months ended December 31, 2008. During the quarter ended December 31, 2009, 88% of capital expenditures were dedicated to drilling and completions.  We spent approximately 32% of our capital expenditures amount on drilling and plugging the Crown 41-31 well in Sheridan County, Montana, 29% on drilling and completion efforts on the Mondak Federal 4-14H well in McKenzie County, North Dakota, 16% in completion costs on the Halvorsen 31X-36, 5% in completion costs on the Kings Canyon 21-27H well in McKenzie County, North Dakota, 4% on recompletion of the Guenther 1-8 in Sheridan County, Montana, and 2% on completion efforts of the Paulson 44-9H in Dunn County, North Dakota.  These projects were funded with cash flow from operations.

At present cash levels, and with the extension of our available borrowing capacity, 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, 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, 2009, we plugged two wells.

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Results of Operations

Overview. Net income for the three and nine months ended December 31, 2009 was $296,000 and $816,000, respectively, compared to net income (loss) of $(1,570,000) and $756,000, respectively, for the three and nine months ended December 31, 2008.  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,
	2009		2008		2009		2008
Sales volume
Oil (barrels)		80,215		72,700		28,606		29,400
Gas (mcf)1		197,192		147,000		77,866		65,100
Revenue
Oil	$	4,824,000	$	6,658,000	$	1,843,000	$	1,552,000
Gas		663,000		1,515,000		174,000		612,000
Total revenue2		5,487,000		8,173,000		2,017,000		2,164,000
Total production expense3		2,143,000		2,490,000		738,000		863,000
Gross profit	$	3,344,000	$	5,683,000	$	1,279,000	$	1,301,000
Depletion expense	$	924,000	$	950,000	$	368,000	$	550,000
Average sales price4
Oil (per barrel)	$	60.14	$	91.57	$	64.43	$	52.80
Gas (per mcf)	$	3.36	$	7.39	$	2.23	$	2.86
Average per BOE
Production expense3,4,5	$	18.95	$	25.62	$	17.75	$	21.41
Gross profit4,5	$	29.57	$	58.47	$	30.76	$	32.28
Depletion expense4,5	$	8.17	$	10.05	$	8.85	$	13.87

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	Net of $12,000 and $39,000 in water service and disposal revenue, to total $2,029,000 and $5,526,000 in revenue for the three and nine months ended December 31, 2009, compared to $41,000 and $86,000 to total $2,205,000 and $8,259,000 for the same period in 2008.
3	Overall lifting cost (oil and gas production expenses and production taxes)
4	Averages calculated based upon non-rounded figures
5	Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)

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Three Months Ended December 31, 2009 Compared to Three Months Ended December 31, 2008

Revenues. Oil and gas sales revenue decreased $147,000 (6.8%) in 2009 from 2008 due to lower realized oil and gas prices. Oil sales revenue increased $291,000 (18.8%), and gas sales revenue decreased $438,000 (71.6%) in 2009 from 2008. 

Volumes and Prices. Oil sales volume decreased 2.7%, from 29,400 barrels in 2008 to 28,606 barrels in 2009 while there was an increase of 22.0% in the average price per barrel from $52.80 in 2008 to $64.43 in 2009. Gas sales volume increased 19.6% from 65,100 thousand cubic feet (Mcf) in 2008 to 77,866 Mcf in 2009, while the average price per Mcf decreased 21.9%, from $2.86 in 2008 to $2.23 in 2009.

The increase in gas sales volume, is primarily due to adjustments made during the quarter ended December 31, 2009, to our revenues, sales volumes, sales prices and severance taxes following the receipt of higher production and sales volume information related to the Antenna Federal property in Weld County, Colorado.  Most of the Company’s gas sales are from our non-operated interest in the Antenna Federal property in Weld County, Colorado.  The Company had estimated gas sales on this property based on the information available at the time and the Company’s experience in the area.  We have recently received actual sales volumes and related information from the operator, which are significantly higher than the sales volumes and related information previously reported to, and accrued by, the Company in prior periods.  The incorporation of this information resulted in higher sales volumes, sales prices and severance taxes for the current quarter.   Due to the adjustments made during the quarter ended December 31, 2009, for updated sales volumes and related information received from the operator of the Antenna Federal property, the higher sales volumes for the quarter ended December 31, 2009, are not representative of actual sales volume for this quarter and should not be used to predict future production or sales volumes.  In addition, production taxes as a percentage of sales, general and administrative expenses as a percentage of sales and any metric whose denominator is related to sales volumes is likely understated.  On an equivalent barrel of oil (BOE) basis, sales volume increased 3.2% from 40,300 BOE in 2008 to 41,584 BOE in 2009.

Expenses. Oil and gas production expense decreased $5,000 (0.7%) in 2009 over 2008, primarily due to workover expense decreasing $92,000 (46.0%) from $200,000 in 2008 to $108,000 in 2009 and routine lease operating expense increasing by $87,000 (16.0%) from $543,000 in 2008 to $630,000 in 2009.  Routine lease operating expense per BOE increased 12.24% from $13.47 in 2008 to $15.15 in 2009 due to the overall increase in gas volumes and corresponding transportation and marketing costs, while workover expense per BOE decreased 47.7% from $4.96 in 2008 to $2.60 in 2009 due to fewer workover operations in 2009.

Production taxes, which are generally a percentage of sales revenue, decreased $120,000 (100.0%) in 2009 compared to 2008. Production taxes, as a percent of sales revenue decreased from 5.4% in 2008 to 0.0% in 2009, due to adjustments made during the quarter ended December 31, 2009 for updated sales volumes and production tax information received from the operator of the Antenna Federal property.  See “Volumes and Prices”above.  The overall lifting cost (oil and gas production expense and production taxes) per BOE decreased 17.1% from $21.41 in 2008 to $17.75 in 2009.

Depreciation, depletion and amortization expense decreased $180,000 (32.3%) in 2009 compared to 2008 as a result of the change in oil and gas volumes as mentioned above.    

General and administrative expense increased $152,000 (40.6%) in 2009 over 2008.  Of the increase, approximately 44.9% related to bonus expense, 44.3% to professional services (audit, legal and consulting fees), 24.7% to increased proxy statement and stockholder meeting expenses, and other categories increased less than 10%.  These expenses were offset during the period by a decrease in bad debt expense of 19.6%.   G&A expense per BOE increased 36.3% from $9.28 in 2008 to $12.65 in 2009. As a percent of total sales revenue, G&A expense increased from 17.0% in 2008 to 25.9% in 2009.

Income Tax Expense (Benefit). For the three months ended December 31, 2009, we recorded an income tax expense of $47,000. This amount consists of a current tax benefit of $55,000 which was reduced by a deferred tax expense of $102,000.  Our effective income tax rate was 13.72% for the three months ended 2009.  

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Nine Months Ended December 31, 2009 Compared to Nine Months Ended December 31, 2008

Revenues. Oil and gas sales revenue decreased $2,686,000 (32.9%) in 2009 from 2008 due to lower realized oil and gas prices. Oil sales revenue decreased $1,834,000 (27.5%), and gas sales revenue decreased $852,000 (56.2%) in 2009 from 2008. 

Volumes and Prices. Oil sales volume increased 10.3%, from 72,700 barrels in 2008 to 80,215 barrels in 2009 while there was a decrease of 34.3% in the average price per barrel from $91.57 in 2008 to $60.14 in 2009. Gas sales volume increased 34.1% from 147,000 thousand cubic feet (Mcf) in 2008 to 197,192 Mcf in 2009, while the average price per Mcf decreased 54.5%, from $7.39 in 2008 to $3.36 in 2009.

The increase in gas sales volume, and to a lesser extent the increase in oil sales volume, is primarily due to adjustments made during the nine months ended December 31, 2009, to our revenues, sales volumes, sales prices and severance taxes following the receipt of higher production and sales volume information related to the Antenna Federal property in Weld County, Colorado.  Most of the Company’s gas sales are from our non-operated interest in the Antenna Federal property in Weld County, Colorado.  The Company had estimated gas sales on this property based on the information available at the time and the Company’s experience in the area.  We have recently received actual sales volumes and related information from the operator, which are significantly higher than the sales volumes and related information previously reported to, and accrued by, the Company in prior periods.  The incorporation of this information resulted in higher sales volumes, sales prices and severance taxes for the current period.  Due to the adjustments made during the nine months ended December 31, 2009, for updated sales volume information received from the operator of the Antenna Federal property, the higher sales volumes for the nine months ended December 31, 2009, are not representative of actual sales volume for this period and should not be used to predict future production or sales volumes.  In addition, production taxes as a percentage of sales, general and administrative expenses as a percentage of sales and any metric whose denominator is related to sales volumes is likely understated.  On an equivalent barrel of oil (BOE) basis, sales volume increased 16.3% from 97,200 BOE in the nine months ended December 31, 2008 to 113,080 BOE in the nine months ended December 31, 2009.

Expenses. Oil and gas production expense decreased $114,000 (6.1%) in 2009 over 2008, primarily due to workover expenses declining by $111,000 (28.4%) from $391,000 in 2008 to $280,000 in 2009 and routine lease operating expense decreasing by $3,000 (0.2%) from $1,481,000 in 2008 to $1,478,000 in 2009.  Routine lease operating expense per BOE decreased 14.2% from $15.24 in 2008 to $13.07 in 2009 due to the overall decrease in costs following the decline in oil and gas prices, while workover expense per BOE decreased 38.4% from $4.02 in 2008 to $2.48 in 2009 due to fewer workover operations in 2009.

Production taxes, which are generally a percentage of sales revenue, decreased $233,000 (37.7%) in 2009 compared to 2008 primarily due to the overall decline of oil prices. Production taxes, as a percent of sales revenue decreased from 7.5% in 2008 to 7.0% in 2009, due to the adjustments made during the nine months ended December 31, 2009 for updated sales volumes and production tax information received from the operator of the Antenna Federal property.  See “Volumes and Prices”above.  The overall lifting cost (oil and gas production expense and production taxes) per BOE decreased 26.0% from $25.62 in 2008 to $18.95 in 2009.

Depreciation, depletion and amortization expense decreased $24,000 (2.5%) in 2009 compared to 2008 as a result of the change in oil and gas volumes mentioned above.

General and administrative expense increased $421,000 (45.2%) in 2009 over 2008.  Of the increase, approximately 55.0% related to professional services (audit, legal and consulting fees), 21.9% in bonus expense, 12.8% in increased proxy statement and stockholder meeting expenses, and other categories increased less than 10%.  G&A expense per BOE increased 24.8% from $9.59 in 2008 to $11.96 in 2009. As a percent of total sales revenue, G&A expense increased from 11.3% in 2008 to 24.5% in 2009.

Income Tax Expense (Benefit). For the nine months ended December 31, 2009 we recorded an income tax expense of $136,000. This includes current period expense of $6,000 and a deferred tax expense of $130,000.  Our effective income tax rate decreased from 15.96% for the nine months ended December 31, 2008 to 14.3% for the nine months ended 2009.  Our effective income tax rate was lower for 2009 primarily due to an increase in estimated deductions for statutory depletion.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4T. 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, 2009, 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, 2009 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

Purchases of Equity Securities

The following table summarizes stock repurchase activity for the three months ended December 31, 2009:

	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, 2009 - Oct 31, 2009	1,400	$	0.80	1,400	258,400
Nov 1, 2009 - Nov 30, 2009	25,750	$	0.78	25,750	1,232,650
Dec 1, 2009 - Dec 31, 2009	15,665	$	0.82	15,665	1,216,985
Total	42,815			42,815

(1) On October 22, 2008, the Company’s board of directors authorized a stock buyback program for the Company to repurchase up to 500,000 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 1,500,000.  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, 2009, 42,815 shares were repurchased under the stock buyback program and 1,216,985 shares remain available for future repurchase.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

The Annual Meeting of Stockholders was held on Tuesday, December 15, 2009 at 9:30 a.m. MST at 1550 Seventeenth Street, Suite 500, Denver, Colorado, 80202.  Voting at this meeting was adjourned on Proposals 3 and 4 until December 18, 2009, and again adjourned on Proposal 4 until December 23, 2009.  The meetings were adjourned to give stockholders additional time to vote on certain proposals. All proposals were approved as of December 23, 2009.  The meeting proposals and voting results are summarized below:

     Proposal No. 1 — Amending and Restating the Certificate of Incorporation. This proposal was to approve certain amendments to our Certificate of Incorporation in order to update, consolidate and clarify the Certificate of Incorporation and conform it with applicable provisions of the Delaware General Corporate Law.

     Proposal No. 2 — Change of Corporate Name to “Earthstone Energy, Inc.” This proposal was to approve an amendment to our Certificate of Incorporation to change the corporate name of the company to “Earthstone Energy, Inc.”

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     Proposal No. 3 — Classified Board and Filling of Vacancies. This proposal was to approve amendments to our Certificate of Incorporation in order to create a classified board of directors and to allow only the Company’s board of directors to fill vacancies.

     Proposal No. 4 — Stockholder Action by Written Consent and Special Meetings of Stockholders. This proposal was to approve amendments to our Certificate of Incorporation in order to provide that stockholder action may be taken only at annual or special meetings of stockholders and not by stockholder written consent and that special meetings of the stockholders may be called only upon the written request of a majority of our board of directors.

     Proposal No. 5 — Supermajority Vote. This proposal was to approve amendments to our Certificate of Incorporation to increase the stockholder vote required to amend or repeal certain features of the existing and proposed Certificate of Incorporation from a majority to 66-2/3%.

     Proposal No. 6 — Reverse Stock Split. This proposal was to approve amendments to our Certificate of Incorporation in order to effect a reverse stock split of the Common Stock at a specific ratio to be determined by our board of directors in its discretion, no later than 12 months after the Annual Meeting, within a range of one for four and one for 12.

     Proposal No. 7 — Election of Directors. This proposal was to elect Ray Singleton, Monroe Robertson, and Richard Rodgers as directors. With the approval of Proposal No. 3 for a classified board of directors,  Ray Singleton was elected as a Class I director to serve a term of one year, Richard Rodgers was elected as a Class II director to serve a term of two years, and Monroe Robertson was elected as a Class III director to serve a term of three years.

     Proposal No. 8 — Ratification of Appointment of Auditors. This proposal was to ratify the appointment of Ehrhardt Keefe Steiner & Hottman PC as our independent registered public accounting firm for the current fiscal year.

The table below reflects the results of voting at the annual meeting in respect of each proposal.

Description	For	Against	Abstain	Total
Proposal 1 – Amend Certificate of Incorporation	13,571,691	887,661	609,287	15,068,639
Proposal 2 – Name Change	14,019,431	834,294	214,914	15,068,639
Proposal 3 – Classified Board of Directors	8,771,458	2,383,622	157,625	11,312,705
Proposal 4 – Special Meetings	8,599,427	2,712,471	107,854	11,419,752
Proposal 5 – Supermajority Vote	8,661,956	2,305,282	45,051	11,012,289
Proposal 6 – Reverse Stock Split	12,997,288	1,988,874	82,477	15,068,639
Proposal 7 – Election of Ray Singleton	13,532,136	1,536,503	—	15,068,639
Proposal 7 – Election of Richard Rodgers	13,630,843	1,437,796	—	15,068,639
Proposal 7 – Election of Monroe Robertson	14,121,251	947,388	—	15,068,639
Proposal 8 – Ratify Auditors	14,166,245	467,578	434,816	15,068,639

In an effort to encourage stockholders to participate in the annual meeting voting process, we engaged Morrow & Company LLC, an outside third party, to contact stockholders of record via mail correspondence and telephone.  The cost of this undertaking was approximately $22,000.

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Item 5. Other Information

None.

Item 6. Exhibits

Exhibit No.	Document
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, 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 Basic Earth Science Systems, Inc.

BASIC EARTH SCIENCE SYSTEMS, INC.

By: /s/ Ray Singleton    

Ray Singleton 

President and Chief Executive Officer 

By: /s/ Joseph Young    

Joseph Young

Principal Accounting Officer 

Date: February 12, 2010