EARTHSTONE ENERGY INC - Quarter Report: 2009 February (Form 10-Q)

e10q_12-08.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, 2008

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.

633 Seventeenth St, Suite 1645

Denver, Colorado 80202-3625

Telephone (303) 296-3076

Incorporated in Delaware

IRS ID# 84-0592823

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

Indicate by check mark whether the registrant 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 17, 2009: 17,505,727

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BASIC EARTH SCIENCE SYSTEMS, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION	Page

Item 1.	Financial Statements	4

	Consolidated Balance Sheets:
	December 31, 2008 (Unaudited) and March 31, 2008	4

	Consolidated Statements of Operations:
	Three and Nine Months Ended December 31, 2008 and 2007 (Unaudited)	6

	Consolidated Statements of Cash Flows:
	Nine Months Ended December 31, 2008 and 2007 (Unaudited)	7

	Notes to Unaudited Consolidated Financial Statements:
	December 31, 2008 (Unaudited)	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18

Item 4.	Controls and Procedures	18

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	19

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	19

Item 3.	Defaults Upon Senior Securities	19

Item 4.	Submission of Matters to a Vote of Security Holders	19

Item 5.	Other Information	20

Item 6.	Exhibits	21

	Signatures	22

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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;

• 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 assets, and depletion rates.

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, including from enhanced recovery

activities;

• costs related to asset retirement obligations;

• 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

• 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, 2008, 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.

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 1 of 2

	December 31,			March 31,
	2008			2008
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	6,313,000		$	5,571,000
Accounts receivable:
Oil and gas sales		1,401,000			1,110,000
Joint interest and other receivables, net of $71,000 and $50,000 in allowance		60,000			236,000
Other current assets		269,000			280,000

Total current assets		8,043,000			7,197,000

Oil and gas property, full cost method:
Proved property		31,826,000			29,050,000
Unproved property		1,270,000			2,515,000
Accumulated depletion and impairment		(22,159,000	)		(18,515,000	)

Net oil and gas property		10,937,000			13,050,000

Support equipment and other non-current assets, net of $331,000 and $299,000 in accumulated depreciation, respectively		437,000			443,000

Total non-current assets		11,374,000			13,493,000

Total assets	$	19,417,000		$	20,690,000

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 2 of 2

	December 31,			March 31,
	2008			2008
	(Unaudited)
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	455,000		$	1,443,000
Accrued liabilities		1,827,000			2,586,000

Total current liabilities		2,282,000			4,029,000

Long-term liabilities:
Deferred tax liability		2,507,000			2,800,000
Asset retirement obligation		1,879,000			1,877,000

Total long-term liabilities		4,386,000			4,677,000

Total liabilities		6,668,000			8,706,000

Shareholders’ 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 17,480,727 shares issued and outstanding		17,000			17,000
Additional paid-in capital		22,822,000			22,798,000
Treasury stock (350,265 shares); at cost		(38,000	)		(23,000	)
Accumulated deficit		(10,052,000	)		(10,808,000	)

Total shareholders’ equity		12,749,000			11,984,000

Total liabilities and shareholders’ equity	$	19,417,000		$	20,690,000

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

(Unaudited)

	Nine Months Ended						Three Months Ended
	December 31,						December 31,
	2008			2007			2008			2007
				(As restated)						(As restated)
Revenues:
Oil and gas sales	$	8,173,000		$	5,472,000		$	2,164,000		$	2,080,000
Well service and water disposal revenue		86,000			17,000			41,000			1,000

Total revenues		8,259,000			5,489,000			2,205,000			2,081,000

Expenses:
Oil and gas production		1,913,000			1,518,000			753,000			561,000
Production tax		618,000			463,000			120,000			180,000
Well servicing expenses		28,000			18,000			6,000			1,000
Depreciation and depletion		976,000			531,000			558,000			175,000
Accretion of asset retirement obligation		54,000			85,000			18,000			37,000
Asset retirement expense		164,000			47,000			35,000			28,000
Impairment of oil and gas properties		2,694,000			―			2,694,000			―
General and administrative		932,000			518,000			374,000			195,000

Total expenses		7,379,000			3,180,000			4,558,000			1,177,000

Income (loss) from operations		880,000			2,309,000			(2,353,000	)		904,000

Other Income (Expense):
Interest and other income		54,000			116,000			12,000			41,000
Interest and other expenses		(27,000	)		(12,000	)		(11,000	)		(4,000	)

Total other income		27,000			104,000			1,000			37,000

Income (loss) before income taxes		907,000			2,413,000			(2,352,000	)		941,000

Current income tax expense		444,000			125,000			76,000			25,000
Provision for deferred income taxes		(293,000	)		1,134,000			(858,000	)		479,000

Total income taxes		151,000			1,259,000			(782,000	)		504,000

Net income (loss)	$	756,000		$	1,154,000		$	(1,570,000	)	$	437,000

Per share amounts:
Basic	$	0.04		$	0.07		$	(0.09	)	$	0.03
Diluted	$	0.04		$	0.07		$	(0.09	)	$	0.03

Weighted average common shares outstanding:
Basic		17,468,613			16,993,676			17,474,638			17,051,709
Diluted		17,490,641			17,133,559			17,474,638			17,135,650

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

		Nine Months Ended
		December 31,
		2008		2007
			(As restated)
Cash flows from operating activities:
Net income	$	756,000	$	1,154,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		976,000		531,000
Deferred tax liability		(293,000)		1,134,000
Accretion of asset retirement obligation		54,000		85,000
Share based compensation		24,000		―
Impairment of Oil and Gas Properties		2,694,000		―
Change in:
Accounts receivable, net		(115,000)		(229,000)
Other assets		(17,000)		91,000
Accounts payable and accrued liabilities		265,000		(124,000)
Other		―		7,000

Net cash provided by operating activities		4,344,000		2,649,000

Cash flows from investing activities:
Oil and gas property		(3,587,000)		(250,000)
Support equipment		―		(16,000)
Proceeds from sale of oil and gas property and equipment		―		14,000
Other		―		(52,000)

Net cash used in investing activities		(3,587,000)		(304,000)

Cash flows from financing activities:
Proceeds from exercise of common stock options		―		14,000
Purchase of treasury shares		(15,000)		―

Net cash provided by (used in) financing activities		(15,000)		14,000

Cash and cash equivalents:
Increase in cash and cash equivalents		742,000		2,359,000
Balance, beginning of year		5,571,000		2,523,000

Balance, end of period	$	6,313,000	$	4,882,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	7,000	$	7,000
Cash paid for income tax	$	487,000	$	―
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	33,000	$	―
Additions to oil and gas also included in accrued liabilities	$	263,000	$	1,078,000

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Notes to Unaudited Consolidated Financial Statements

December 31, 2008

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 all adjustments, consisting of normal recurring 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 its public filings, the Company will use such terms as “we”, “our” and “us” in place of Basic Earth Science Systems, Inc. or “the Company.” 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 notes hereto included in our Annual Report on Form 10-KSB for the year ended March 31, 2008.

1. Presentation of Consolidated Financial Statements

As discussed in our 2008 Annual Report on Form 10-KSB for the fiscal year ended March 31, 2008, we discovered during the preparation and review of our 2008 income tax provision that errors occurred in calculating the GAAP cost basis of our oil and gas properties in determining tax liability and the estimated deferred tax asset for percentage depletion carryforward. These errors impacted our previously filed financial statements for fiscal years ended March 31, 2007 and 2006 and our previously filed interim financial statements for those years and the first three quarters of 2008. For further information concerning the restatement and details concerning restated amounts, please refer to our previously filed Annual Report on Form 10-KSB for the fiscal year ended March 31, 2008.

The following table summarizes the impact of these corrections to our consolidated statement of income for the fiscal quarter ended December 31, 2007, as previously presented in Footnote 13 – Quarterly Financial Data (Unaudited) of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2007. There was no impact to our 2008 interim Net Cash provided by Operating Activities due to the correction of the above errors.

Impact to the Income Statement	Nine Months Ended December 31, 2007							Three Months Ended December 31, 2007
(Unaudited)	As reported		Adjustment			As restated		As reported		Adjustment			As restated

Provision for deferred income taxes	$	759,000	$	375,000		$	1,134,000	$	354,000	$	125,000		$	479,000
Total income taxes		884,000		375,000			1,259,000		379,000		125,000			504,000

Net Income	$	1,529,000	$	(375,000	)	$	1,154,000	$	562,000	$	(125,000	)	$	437,000

Per share amounts:
Basic	$	0.09	$	(0.02	)	$	0.07	$	0.03	$	(0.00	)	$	0.03
Diluted	$	0.09	$	(0.02	)	$	0.07	$	0.03	$	(0.00	)	$	0.03

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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 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.

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.

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 quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. At March 31, 2008, ninety-five 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 five percent of our oil and gas reserves were prepared in-house.

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 determination of depletion expense, as well as ceiling test write-downs, are highly dependent on these reserve, and quarterly “re-pricing” estimates.

Oil and Gas Property. We utilize the full cost method of accounting for costs related to our oil and gas property. Capitalized costs included in the full cost pool are depleted on an aggregate basis over the estimated lives of the properties using the units-of-production method. 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 market 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 shareholders’ 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 December 31, 2008, we determined that our capitalized costs exceeded the ceiling test limit. Accordingly, we recorded an impairment write down of $2,694,000 representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules for both the quarter and nine months ended December 31, 2008.

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Asset Retirement Obligations. We have obligations related to the plugging and abandonment of our oil and gas wells, the removal of equipment and facilities, and returning the land to its original condition. SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that we estimate the future cost of this obligation, 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 many 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 income; 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. Since our initial adoption of FASB No. 143 we have closed gains and losses on asset retirements to the income statement as a component of asset retirement expense.

The information below reconciles the value of the asset retirement obligation for the period presented.

	Nine Months Ended December 31, 2008

Balance beginning of period	$	2,179,000
Liabilities incurred		33,000
Liabilities settled		(160,000	)
Revisions in estimated cash flows		(3,000	)
Accretion expense		54,000

Balance end of period	$	2,103,000

Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”. Accordingly, deferred tax liabilities and assets 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.

On April 1, 2007 we adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48). The adoption of FIN 48 had no impact on our consolidated financial statements. 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 2004 through 2006. We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2008, we made no provisions for interest or penalties related to uncertain tax positions.

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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.

Off Balance Sheet Transactions, Arrangements, or Obligations

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

Recent Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R will significantly change the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, research and development assets and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. SFAS 141R is effective for fiscal years beginning after December 15, 2008. The adoption of the provisions of SFAS 141R is not expected to have a material effect on our financial position, results of operations, or cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, providing companies with an option to report selected financial assets and liabilities at fair value. The Standard’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. Generally accepted accounting principles have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. SFAS 159 helps to mitigate this type of accounting-induced volatility by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with detailed rules for hedge accounting. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of our choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the Company has chosen to use fair value on the face of the balance sheet. The adoption of the provisions of SFAS 159 did not have a material effect on our financial position, results of operations, or cash flows.

In September 2006, the FASB issued SFAS Statement No. 157, “Fair Value Measurements”. SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued Staff Position No. FAS 157-2. That guidance proposed a one year deferral of the implementation of SFAS 157 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 SFAS No. 157 with the one-year deferral for non-financial assets and liabilities. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations, or cash flows. Beginning April 1, 2009, we expect to adopt 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. While we are in the process of evaluating this standard with respect to its effect on non- financial assets and liabilities, we have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

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3. Subsequent Events

On January 14, 2009, FieldPoint Petroleum Corporation announced that it had filed a Registration Statement on Form S-4 to register shares of its common stock proposed to be issued in connection with a potential exchange offer for a minimum of 51% and a maximum of 100% of the outstanding shares of the Company’s common stock. The exchange ratio that FieldPoint has disclosed is one share of FieldPoint common stock for every two shares of the Company’s common stock and would be subject to a number of conditions. FieldPoint did not have any substantive communications with the Company before issuing its press release.

On February 4, 2009, our Board of Directors (the “Board”) declared a dividend (the “Dividend”) of one preferred share purchase right (a “Right”) for each outstanding share of common stock. The dividend is payable on February 17, 2009 to holders of record on that date. On February 4, 2009, we entered into a Rights Agreement, with Corporate Stock Transfer, Inc. as the Rights Agent (the “Rights Agreement”), specifying the terms of the Rights.

The Board has authorized the adoption of a Rights Agreement to protect stockholders from coercive or otherwise unfair takeover tactics. In general terms, the Rights impose a significant penalty upon any person or group that acquires beneficial ownership of 15% or more of our outstanding common stock without the prior approval of the Board. The Rights Agreement will provide an exemption for (i) any person who is, as of February 17, 2009, the beneficial owner of 15% or more of our outstanding common stock, so long as such person does not, subject to certain exceptions, acquire additional common stock of the Company after February 17, 2009, and (ii) Ray J. Singleton, Jr., the Company’s President and Chief Executive Officer, and his family and certain affiliates (collectively, the “Grandfathered Persons”), so long as such Grandfathered Persons, individually or in the aggregate, do not, subject to certain exceptions, acquire additional common stock of the Company such that their aggregate ownership exceeds 36% of the then outstanding common stock of the Company. Mr. Singleton currently owns approximately 26% of our outstanding common stock. The Company, its subsidiaries, employee benefit plans of the Company or any of its subsidiaries, and any entity holding common stock for or pursuant to the terms of any such plan will also be excepted.

In connection with the adoption of the Rights Agreement on February 4, 2009, we filed a Certificate of Designations of Series A Junior Participating Preferred Stock (the “Certificate of Designations”) with the Secretary of State of the State of Delaware to create the Preferred Shares.

Also on February 4, 2009, we amended our bylaws to add a provision requiring a stockholder who seeks to present business or to nominate directors for election at a stockholders’ meeting to provide notice to us in advance of the meeting and to include in such notice certain disclosures about the stockholder and the business to be proposed.

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Item 2. Management’s Discussion and Analysis and Plan of Operation

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 fiscal year and beyond.

Working Capital. At December 31, 2008, we had a working capital surplus of $5,761,000 (a current ratio of 3.52:1) compared to a working capital surplus at March 31, 2008 of $3,168,000 (a current ratio of 1.79:1). The increase is a result of our improved cash position due to overall increases in price and production of oil and gas for the nine month period ended December 31, 2008.

Cash Flow. Net cash provided by operating activities increased 64% from $2,649,000 in the nine months ended December 31, 2007 (“2007”) to $4,344,000 in the nine months ended December 31, 2008 (“2008”) due to increased oil commodity prices and production volumes in the latest nine month period. While not reflected on the Consolidated Statement of Income, this level of cash flow was determined by reconciling net income with, among other things, impairment and depletion expense within the “net cash provided by operating activities” section.

Net cash used in investing activities increased 1,080% from $304,000 during 2007 to $3,587,000 in the nine months ended December 31, 2008. The difference relates primarily to timing of cash payments relating to expenditures of the drilling and completion of the new wells in DJ Basin of Colorado. We also used a de minimis amount of cash for our stock buyback program. (For further information refer to Part II, Item 2. Unregistered Sales of Equity Securities and Use of Proceeds).

Credit Line. Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Subject to several amendments over time, the line of credit amount was set at $20,000,000 with a concurrent borrowing base of $4,000,000. 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, 2008 and for the nine months ending December 31, 2008, we did not utilize our credit facility. The loan contains several covenant restrictions. Since inception this loan facility has contained a covenant that makes the loan callable upon a change of control. At December 31, 2008, 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 we cannot envision at this time.

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 in that the amounts contained therein are presented on a cash basis.

During the quarter ended December 31, 2008, we spent approximately $353,000 on various projects. When combined with first and second quarter investments, we have deployed $1,568,000 through the first nine months of the current fiscal year. This compares to $945,000 and $1,328,000 for the quarter and nine months ended December 31, 2007, respectively. Through the first nine months of fiscal 2008, approximately 83% of capital expenditures were dedicated to drilling and completions, 7% was dedicated to preservation of expiring leases and 10% was dedicated to the acquisition of producing properties.

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During the quarter ended December 31, 2008, we estimate that we spent 51% of our capital expenditure amount on the Crown 41-31 project in Montana, and 23% on workovers for the Halverson 21-36 in Richland County, Montana. These projects were funded with internally generated cash flow from operations.

Panther Energy Company, LLC. (Panther), the operator of the Company’s Banks Prospect in eastern McKenzie County, North Dakota, drilled a second well on that prospect. In addition, Panther attempted twice to hydraulically stimulate the first well on the prospect but had to postpone its operations due to adverse winter weather conditions. Panther has informed the Company that Panther intends to move its rig to Montana to drill two wells for a third party and then return to the Banks Prospect in late spring. The Company will evaluate the drilling results for these two wells before committing the Company to fund capital expenditures related to additional wells on the Banks Prospect. The Company has a 6.5% (32.5% of 20%) carried working interest “to the tanks” on the Banks acreage contributed to the spacing unit on each well. Pursuant to the Farmout Agreement between the Company and Panther, Panther earned its 67.5% interest in the Banks acreage upon completion of the second well. The Company has the right to participate in wells for a 6.5% working interest on the Banks acreage contributed to any spacing unit in the future.

Due to the precipitous drop in oil commodity prices and the relatively high service company prices, the Company and its 50% partner at the South Flat Lake prospect in Montana re-evaluated the economics of a vertical Red River test well on the prospect and decided to postpone drilling. If commodity prices and drilling costs improve, the Company and its partner would drill an initial well at a total cost estimated currently to be approximately $1.35 million.

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 these 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 other 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, 2008 we plugged no additional wells. Instead, all expenses incurred during the quarter were for surface restoration.

Results of Operations

Overview. Net loss for the three months ended December 31, 2008 was $1,570,000 compared to net income of $437,000, as restated, for the three months ended December 31, 2007. Net income for the nine months ended December 31, 2008 was $756,000 compared to net income of $1,154,000 as restated for the nine months ended December 31, 2007.

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The following table shows selected financial information for the quarter 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,
	2008		2007		2008		2007
Sales volume
Oil (barrels)		72,700		68,300		29,400		23,200
Gas (mcf)		147,000		88,100		65,100		23,500

Revenue
Oil	$	6,658,000	$	4,891,000	$	1,552,000	$	1,921,000
Gas		1,515,000		581,000		612,000		159,000
Total revenue1		8,173,000		5,472,000		2,164,000		2,080,000

Total production expense2		2,490,000		1,981,000		863,000		741,000

Gross profit	$	5,683,000	$	3,491,000	$	1,301,000	$	1,339,000

Depletion expense	$	950,000	$	523,000	$	550,000	$	172,000

Average sales price3
Oil (per barrel)	$	91.57	$	71.61	$	52.80	$	82.62
Gas (per mcf)	$	7.39	$	6.60	$	2.86	$	6.76
Average production expense2,3,4	$	25.62	$	23.87	$	21.41	$	27.24
Average gross profit3,4	$	58.47	$	42.08	$	32.28	$	49.31
Average depletion expense3,4	$	10.05	$	6.30	$	13.87	$	6.34
Average general and administrative expense3,4	$	9.59	$	6.25	$	9.28	$	7.19

1		Net of $86,000 in water disposal revenue, as compared to total revenues of $8,259,000
2		Overall lifting cost (oil and gas production expenses and production taxes)
3		Averages calculated based upon non-rounded figures
4		Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)

Three Months Ended December 31, 2008 Compared to Three Months Ended December 31, 2007

Revenues. Oil and gas sales revenue increased $84,000 (4%) in 2008 from 2007 due to increased production partially offset by decreased prices. Oil sales revenue decreased $369,000 (19%), and gas sales revenue increased $453,000 (285%) in 2008 from 2007.

Volumes and Prices. Oil sales volumes increased 27%, from 23,200 barrels in 2007 to 29,400 barrels in 2008 while there was a decrease of 36% in the average price per barrel from $82.62 in 2007 to $52.80 in 2008. The increase in oil sales volume is attributed primarily to the production of our Antenna Federal property in Weld County, Colorado. Gas sales volume increased 177% from 23.5 million cubic feet (MMcf) in 2007 to 65.1 MMcf in 2008, while the average price per Mcf decreased 58%, from $6.76 in 2007 to $2.86 in 2008. The increase in gas sales volume is primarily due to bringing back online wells in the Antenna Federal property in Weld County, Colorado, as well as the production of new wells in the same property. On an equivalent barrel (BOE) basis, sales volume increased 48% from 27,200 BOE in 2007 to 40,300 BOE in 2008.

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Expenses. Oil and gas production expense increased $182,000 (32%) in 2008 over 2007. Oil and gas production expense is comprised of two components: routine lease operating expenses and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal, minor surface equipment repairs, and marketing and transportation costs. Workovers, on the other hand, which primarily include downhole repairs, are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their cost can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas production expense from period to period.

Routine lease operating expense increased $116,000 (27%) from $427,000 in 2007 to $543,000 in 2008, primarily due to higher production volumes, while workover expense increased $66,000 (49%) from $134,000 in 2007 to $200,000 in 2008. Routine lease operating expense per BOE decreased 14% from $15.71 in 2007 to $13.47 in 2008 while workover expense per BOE increased 1% from $4.92 in 2007 to $4.96 in 2008.

Production taxes, which are generally a percentage of sales revenue, decreased $60,000 (33%) in 2008 compared to 2007 primarily due to the decline of oil prices. Production taxes, as a percent of sales revenue decreased from 9% in 2007 to 5% in 2008. The overall lifting cost (oil and gas production expense and production taxes) per BOE decreased 21% from $27.24 in 2007 to $21.41 in 2008.

Depreciation and depletion expense increased $384,000 (219%) in 2008 compared to 2007 as a result of a decrease in our reserve values due to the decline in oil and gas prices. In addition, we recorded an impairment write down of $2,694,000 representing the excess of capitalized costs over the ceiling, as calculated in accordance with full cost rules for both the quarter and nine months ended December 31, 2008. For further discussion concerning the ceiling test limitations, see Note 2 under “Oil and Gas Property.”

General and administrative expense increased $179,000 (92%) in 2008 over 2007. These increases were primarily the result of increased expenditures attributable to the restatement of our financial statements, along with increases in consulting fees, and to a lesser extent, increases in the number of office personnel. G&A expense per BOE increased 29% from $7.19 in 2007 to $9.28 in 2008. As a percent of total sales revenue, G&A expense increased from 9% in 2007 to 17% in 2008.

Nine Months Ended December 31, 2008 Compared to Nine Months Ended December 31, 2007

Revenues. Oil and gas sales revenue increased $2,701,000 (49%) in 2008 from 2007. Oil sales revenue increased $1,767,000 (36%). Gas sales revenue increased $934,000 (161%) in 2008 from 2007.

Volumes and Prices. Oil sales volumes increased 6%, from 68,300 barrels in 2007 to 72,700 barrels in 2008 while there was a 28% increase in the average price per barrel from $71.61 in 2007 to $91.57 in 2008. Gas sales volume increased 67%, from 88.1 million cubic feet (MMcf) in 2007 to 147 MMcf in 2008, while the average price per Mcf increased 12%, from $6.60 in 2007 to $7.39 in 2008. The increase in gas sales volume is primarily due to production brought online from our 16-well drilling program in Weld County, Colorado. On an equivalent barrel (BOE) basis, sales volume increased 17% from 83,000 BOE in 2007 to 97,200 BOE in 2008.

Expenses. Oil and gas production expense increased $354,000 (23%) in 2008 over 2007. Oil and gas production expense is comprised of two components: routine lease operating expenses and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal and minor surface equipment repairs. Workovers, on the other hand, which primarily include downhole repairs, are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their cost can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas production expense from period to period.

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Routine lease operating expense increased $270,000 (22%) from $1,211,000 in 2007 to $1,481,000 in 2008 primarily due to higher production volumes, while workover expense increased $84,000 (27%) from $307,000 in 2007 to $391,000 in 2008. Routine lease operating expense per BOE increased 4% from $14.59 in 2007 to $15.24 in 2008 while workover expense per BOE increased 9% from $3.70 in 2007 to $4.02 in 2008.

Production taxes, which are generally a percentage of sales revenue, increased $155,000 (33%) in 2008 over 2007. Production taxes, as a percent of sales revenue decreased from 8% in 2007 to 7% in 2008. The overall lifting cost (oil and gas production expense and production taxes) per BOE increased 7% from $23.87 in 2007 to $25.62 in 2008.

Depreciation and depletion expense increased $445,000 (84%) in 2008 over 2007 as a result of a decrease in our reserve values due to the decline in oil and gas prices. In addition, we recorded an impairment write down of $2,694,000 representing the excess of capitalized costs over the ceiling, as calculated in accordance with full cost rules for both the quarter and nine months ended December 31, 2008. For further discussion concerning the ceiling test limitations, see Note 2 under “Oil and Gas Property.”

General and administrative expense increased $414,000 (80%) in 2008 over 2007. These increases were primarily the result of increased expenditures attributable to the restatement of our financial statements, implementation of Sarbanes-Oxley 404 requirements, along with increases in consulting fees, and to a lesser extent, increases in the number of office personnel. G&A expense per BOE increased 53% from $6.25 in 2007 to $9.59 in 2008. As a percent of total sales revenue, G&A expense increased from 10% in 2007 to 11% in 2008.

Income Tax Expense. For the nine months ended December 31, 2008 we recorded income tax expense of $151,000. This includes a current year expense of $444,000 and a deferred tax provision of $(293,000). Our effective income tax rate decreased from 53.56% for the nine months ended December 31, 2007 to 15.96% for 2008. Our effective income tax rate was lower for 2008 primarily due to an increase in estimated deductions for statutory depletion relative to pre-tax net income.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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.

Item 4. Controls and Procedures

The Company maintains a system of disclosure controls and procedures that are designed for the purpose of ensuring 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 Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

For the quarter ended December 31, 2008 we carried out an evaluation, under the supervision and with the participation of the Company’s Chief Executive Officer and Principal Accounting Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, it was 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, 2008 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 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, 2008:

	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)

October 1, 2008—October 31, 2008	—	$	—	—	500,000
November 1, 2008—November 30, 2008	—		—	—	500,000
December 1, 2008—December 31, 2008	21,600	$	0.6653	21,600	478,400

Total	21,600			21,600

(1)

In October 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. The program does not have a specified expiration date, it does not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time. During the three months ended December 31, 2008, 21,600 shares were repurchased under the stock buyback program and 478,400 shares remain available for future repurchase.

Item 3. Defaults Upon Senior Securities

None.

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

On December 8, 2008, the Company held its Annual Meeting of Shareholders to elect three directors to its Board of Directors. In the election of directors, each nominee was elected by a vote of the shareholders as follows:

Director	For	Withheld
Monroe W. Robertson	13,881,297	3,584,288
Richard Rodgers	13,168,648	4,296,937
Ray Singleton	13,168,248	4,297,337

There were no other matters submitted to a vote at the Annual Meeting of Shareholders.

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Item 5. Other Information

On February 5, 2009, the Company filed a Current Report on Form 8-K to report that the Company’s Board of Directors had adopted a Stockholders Rights Plan and declared a dividend of one preferred share purchase right for each outstanding share of common stock, payable to holders of record on February 17, 2009.

On February 4, 2009, the Board of Directors amended the Company’s Bylaws to add a provision requiring a stockholder who seeks to present business or to nominate directors for election at a stockholders’ meeting to provide notice to the Company in advance of the meeting and to include in such notice certain disclosures about the stockholder and the business to be proposed. A copy of the Company’s Bylaws, as amended, is filed with this report and is incorporated herein by reference.

To propose nominations for director at a meeting of stockholders, a stockholder must timely submit a stockholder’s notice in accordance with Section 6 of the Company’s bylaws. To be timely, a stockholder must provide notice to the Company’s secretary not less than 90 days nor more than 120 days prior to the date of the meeting. A stockholder’s notice regarding nominations of persons for election to the Board of Directors must set forth: (a) as to each proposed nominee, (i) the name, age, business address and residence address of the nominee, (ii) the principal occupation or employment of the nominee, (iii) the class or series and number of shares of capital stock of the corporation that are owned beneficially or of record by the nominee and (iv) any other information relating to the nominee that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules and regulations promulgated thereunder; and (b) as to the stockholder giving the notice, (i) the name and record address of such stockholder, (ii) the class or series and number of shares of capital stock of the corporation which are owned beneficially or of record by such stockholder, (iii) all other ownership interests of such stockholder, including derivatives, hedged positions, synthetic and temporary ownership techniques, swaps, securities, loans, timed purchases and other economic and voting interests, (iv) a description of all arrangements or understandings between such stockholder and each proposed nominee and any other person or persons (including their names) pursuant to which the nomination(s) are to be made by such stockholder, (v) a representation that such stockholder intends to appear in person or by proxy at the meeting to nominate the persons named in such stockholder’s notice and (vi) any other information relating to such stockholder that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder.

Such stockholder’s notice must be accompanied by a written consent of each proposed nominee to being named as a nominee and to serve as a director if elected. In addition, each proposed nominee will be required to complete a questionnaire, in a form to be provided by the Company, to be submitted with the stockholder’s notice. The Company may also require any proposed nominee to furnish such other information as may reasonably be required by the Company to determine the eligibility of such proposed nominee to serve as an independent director of the Company or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such nominee.

Determinations of the chairman of the meeting as to whether those procedures were complied with in a particular case shall be final and binding.

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Item 6. Exhibits

Exhibit No.		Document

3(i)		Restated Certificate of Incorporation of Basic Earth Science Systems, Inc., effective May 12, 1981, as amended by (i) Certificate of Amendment of Certificate of Incorporation, effective November 20, 1986; (ii) Certificate of Amendment of Certificate of Incorporation, effective July 1, 1996; and (iii) Certificate of Designations of Series A Junior Participating Preferred Stock, effective February 5, 2009.
3(ii)		Bylaws of Basic Earth Science Systems, Inc., dated July 15, 1986, as amended by First Amendment to Bylaws, dated February 4, 2009.
10.1		Amendment of Credit Agreement, dated effective December 31, 2008, by and between Basic Earth Science Systems, Inc. and American National Bank.

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.


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 17, 2009