UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-QSB

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

For the Quarterly Period Ended December 31, 2007

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.

1801 Broadway, Suite 620
Denver, Colorado 80202-3835
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

Check whether the issuer is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definitions in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Check whether the issuer is a shell Company (as defined in Rule 12b-2 of the Exchange Act).     Yes o     No þ

Shares of common stock outstanding on February 8, 2008: 17,120,187

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BASIC EARTH SCIENCE SYSTEMS, INC.

FORM 10-QSB
INDEX

PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	3
		Consolidated Balance Sheets — December 31, 2007 and March 31, 2007	3
		Consolidated Statements of Operations — Quarters and Nine Months Ended December 31, 2007 and December 31, 2006	5
		Consolidated Statements of Cash Flows — Nine Months Ended December 31, 2007 and December 31, 2006	6
		Notes to Consolidated Financial Statements	7
	Item 2.	Management’s Discussion and Analysis and Plan of Operation	8
		Results of Operations	10
	Item 3.	Controls and Procedures	15
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	15
	Item 2.	Changes in Securities	15
	Item 3.	Defaults Upon Senior Securities	15
	Item 4.	Submission of Matters to a Vote of Security Holders	15
	Item 5.	Other Information	16
	Item 6.	Exhibits	16
	Signatures		16
EXHIBITS
	Certification of Chief Executive Officer Pursuant to Section 302
	Certification of Chief Financial Officer Pursuant to Section 302
	Certification of Chief Executive Officer Pursuant to Section 906
	Certification of Chief Financial Officer Pursuant to Section 906
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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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
	2007			2007
	(Unaudited)			(Audited)
Assets
Current assets:
Cash and cash equivalents	$	4,882,000		$	2,523,000
Accounts receivable:
Oil and gas sales		986,000			825,000
Joint interest and other receivables, net		570,000			436,000
Other current assets		193,000			262,000
Total current assets		6,631,000			4,046,000
Oil and gas property, full cost method:
Proved property		28,401,000			27,686,000
Unproved property		2,127,000			1,199,000
Accumulated depreciation and depletion		(18,365,000	)		(17,842,000	)
Net oil and gas property		12,163,000			11,043,000
Other non-current assets, net		396,000			363,000
Total non-current assets		12,559,000			11,406,000
Total Assets	$	19,190,000		$	15,452,000

See accompanying notes to consolidated financial statements.

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Basic Earth Science Systems, Inc.
Consolidated Balance Sheets
Page 2 of 2

	December 31			March 31
	2007			2007
	(Unaudited)			(Audited)
Liabilities
Current liabilities:
Accounts payable	$	240,000		$	744,000
Accrued liabilities		2,919,000			1,245,000
Total current liabilities		3,159,000			1,989,000
Long-term liabilities:
Deferred tax liability		1,340,000			581,000
Asset retirement obligation		2,068,000			1,802,000
Total long-term liabilities		3,408,000			2,383,000
Shareholders’ Equity
Preferred stock, $.001 par value
Authorized — 3,000,000 shares
Issued — 0 shares		—			—
Common stock, $.001 par value
32,000,000 shares authorized;
17,469,752 shares issued at December 31 and 17,304,752 at March 31		17,000			17,000
Additional paid-in capital		22,744,000			22,730,000
Accumulated deficit		(10,115,000	)		(11,644,000	)
Treasury stock (349,565 shares at December 31 and 349,265 March 31); at cost		(23,000	)		(23,000	)
Total shareholders’ equity		12,623,000			11,080,000
Total Liabilities and Shareholders’ Equity	$	19,190,000		$	15,452,000

See accompanying notes to consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

(Unaudited)

	Nine Months Ended						Quarters Ended
	December 31						December 31
	2007			2006			2007			2006
Revenue
Oil and gas sales	$	5,472,000		$	5,600,000		$	2,080,000		$	1,579,000
Well service revenue		17,000			31,000			1,000			6,000
Total revenue		5,489,000			5,631,000			2,081,000			1,585,000
Expenses
Oil and gas production		1,518,000			1,404,000			561,000			496,000
Production tax		463,000			378,000			180,000			113,000
Well service expenses		18,000			34,000			1,000			6,000
Depreciation and depletion		531,000			450,000			175,000			145,000
Accretion of asset retirement obligation		85,000			53,000			37,000			14,000
Asset retirement expense		47,000			113,000			28,000			19,000
General and administrative		518,000			405,000			195,000			132,000
Total operating expenses		3,180,000			2,837,000			1,177,000			925,000
Income from operations		2,309,000			2,794,000			904,000			660,000
Other income (expense)
Interest and other income		116,000			28,000			41,000			19,000
Interest and other expenses		(12,000	)		(6,000	)		(4,000	)		—
Total other income		104,000			22,000			37,000			19,000
Income before income taxes		2,413,000			2,816,000			941,000			679,000
Current income tax expense		125,000			262,000			25,000			235,000
Provision for deferred taxes		759,000			779,000			354,000			166,000
Total income taxes		884,000			1,041,000			379,000			401,000
Net income	$	1,529,000		$	1,775,000		$	562,000		$	278,000
Net income per share:
Basic	$	.090		$	.106		$	.033		$	.017
Diluted	$	.089		$	.103		$	.033		$	.016
Weighted average common shares outstanding:
Basic		16,993,676			16,795,124			17,051,709			16,805,487
Diluted		17,133,559			17,128,937			17,135,650			17,128,726

See accompanying notes to consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	December 31
	2007			2006
Cash flows from operating activities:
Net income	$	1,529,000		$	1,775,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		531,000			450,000
Deferred tax liability		759,000			779,000
Accretion of asset retirement obligation		85,000			53,000
Change in:
Accounts receivable, net		(229,000	)		28,000
Other assets		91,000			95,000
Accounts payable and accrued liabilities		(124,000	)		(5,000	)
Other		7,000			5,000
Net cash provided by operating activities		2,649,000			3,180,000
Cash flows from investing activities:
Capital expenditures:
Oil and gas property		(250,000	)		(1,171,000	)
Support equipment		(16,000	)		(37,000	)
Insurance settlement		—			161,000
Proceeds from sale of oil and gas property and equipment		14,000			15,000
Other		(52,000	)		(6,000	)
Net cash used in investing activities		(304,000	)		(1,038,000	)
Cash flows from financing activities:
Proceeds from exercise of common stock options		14,000			3,000
Proceeds from borrowing		—			565,000
Long-term debt payments		—			(1,010,000	)
Net cash provided by (used in) financing activities		14,000			(442,000	)
Cash and cash equivalents:
Net increase		2,359,000			1,700,000
Balance at beginning of period		2,523,000			78,000
Balance at end of period	$	4,882,000		$	1,778,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	7,000		$	6,000
Net additions to oil and gas property included in accrued liabilities	$	1,078,000		$	264,000

See accompanying notes to consolidated financial statements.

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Basic Earth Science Systems, Inc.

Notes to Consolidated Financial Statements

December 31, 2007

The accompanying interim financial statements of Basic Earth Science Systems, Inc. (sometimes referred to as the Company) 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 condensed financial statements be read in conjunction with the financial statements and notes hereto included in our Form 10-KSB for the year ended March 31, 2007.

Forward-Looking Statements

This Form 10-QSB includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-QSB, including, without limitation, the statements under both “Notes to Consolidated Financial Statements” and “Item 2. Management’s Discussion and Analysis or Plan of Operation” located elsewhere herein regarding the Company’s financial position and liquidity, the amount of and its ability to make debt service payments, its strategies, financial instruments, and other matters, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations are disclosed in this Form 10-QSB.

1. Summary of Significant Accounting Policies

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.

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 reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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.

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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.

For the nine months ended December 31, 2007 we recorded income tax expense of $884,000. This includes a current year expense of $125,000 and a deferred tax provision of $759,000. 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. During the quarter ended December 31, 2007, as a result of a downward adjustment to our statutory depletion carryforward deferred tax asset, we recorded an additional $56,000 provision for deferred taxes.

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, 2007 we made no provisions for interest or penalties related to uncertain tax positions.

Reclassifications. Certain prior year amounts were reclassified to conform to current year presentation. Such reclassifications had no effect on 2007 net income.

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 significantly from current levels, we believe the cash generated from operations will enable us to meet our existing and normal recurring obligations as they become due in fiscal 2008. In addition, as mentioned in the “Bank Debt” section below, Basic has $4,000,000 of borrowing capacity as of February 8, 2008.

Working Capital. At December 31, 2007 we had a working capital surplus of $3,472,000 (a current ratio of 2.10:1) compared to a working capital surplus at March 31, 2007 of $2,057,000 (a current ratio of 2.03:1). The increase from March 31 to December 31 is primarily a result of our improved cash position.

Cash Flow. Net cash provided by operating activities decreased 17% from $3,180,000 in the nine months ended December 31, 2006 to $2,649,000 in the nine months ended December 31, 2007. This decrease was primarily due to a $263,000 negative variance from the changes in net accounts receivable and accounts payable and accrued liabilities and the decrease in net income.

8

Net cash used in investing activities decreased 71% from $1,038,000 in 2006 to $304,000 in 2007. Adding in the net additions to oil and gas property included in accrued liabilities, our total investment in oil and gas property for 2007 and 2006 was $1,328,000 and $1,435,000, respectively. Although our 2007 investment of $1,328,000 is about 7% shy of our $1,435,000 2006 investment, our oil and gas property capital expenditures in the fourth quarter will push our fiscal 2008 investment beyond our fiscal 2007 total of $1,703,000.

Bank Debt. Our current banking relationship, established in March 2002, is with American National Bank, located in Denver, Colorado. Under the terms of our loan agreement, we have a $20,000,000 line of credit and a current borrowing base of $4,000,000 with a maturity date of December 31, 2008. The interest rate is the prime rate plus one-quarter of one percent (0.25%). We are also required to pay an Unused Commitment fee of one-half of one percent (0.50%) per annum on the difference between the outstanding balance and the borrowing base amount.

In the past we have utilized our credit facility to fund short-term working capital needs, finance drilling and/or re-completion efforts and fund property acquisitions, and may do so in the future.

Hedging. In the past we have used hedging techniques to limit our exposure to oil price fluctuations. Typically we will utilize either futures or option contracts. We did not hedge any of our production during the nine months ended December 31, 2007 and at December 31, 2007 we had no open futures, forwards or option contracts in place to hedge future production.

CAPITAL EXPENDITURES

During the quarter ended December 31, 2007, we estimate that we spent $945,000 on various projects. When combined with first and second quarter investments, we have deployed $1,328,000 through the first nine months of the current fiscal year. This compares to $627,000 and $1,435,000 for the quarter and nine months ended December 31, 2006, respectively. Through the first nine months of fiscal 2008, approximately $1,144,000 (86%) of expenditures were dedicated to our Antenna Federal development drilling project in Weld County, Colorado while stimulation efforts on the Lynn #3H, in Billings County, North Dakota accounted for an additional $50,000 (4%). No other activity accounted for more than 3% of total expenditures.

Contemplated Activities

In addition to the discussion in Capital Expenditures described above, we anticipate pursuing the following activities during the remainder of fiscal 2008.

As noted above, we are in the midst of a sixteen well continuous development drilling and completion program on our Antenna Federal project. While the majority of wells have been drilled to the Codell formation, five wells were drilled to the deeper J-Sand formation. We expect to have a 2% to 16.375% revenue interest in Codell production and a 13.125% to 52.5% revenue interest in J-Sand production (depending on actual well location). Production equipment is currently being installed on all of the new wells. While initial completion work has begun on four wells, stimulation has only occurred on one well. We expect to spend an additional $600,000 for our share of the cost of completing these wells. Kerr-McGee Oil & Gas Onshore, LP is the operator of this project.

In Montana, the Company and its 50% partner expect to drill a vertical Red River test on the South Flat Lake prospect in the first quarter of fiscal 2009. If successful, it is possible that as many as 4 development wells could be drilled. The initial well is expected to cost approximately $1.25 million to drill. While we now own, and could participate for our 50% interest in this prospect, if we and our partner sell a portion of this prospect as intended, our interest would be proportionately reduced. We expect to be the operator of this property.

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In the TR Madison Unit, following the success of the well we drilled last summer, we have been notified to plan to drill three to five additional horizontal wells during the 2008 calendar year. These wells are estimated to cost $2.8 million each or $30,000 for our 1% interest. Encore Acquisition Company is the operator of this project.

With the success of EOG Resources, Inc. and others in Mountrail County, North Dakota, new life has been given to the horizontal Bakken play in North Dakota. As these successful ventures have expanded from their core discovery wells, they have neared the eastern boundary of our Banks prospect. If these wells are successful, the viability of the Bakken formation in our Banks Prospect should become more attractive. If development were to occur at an accelerated pace, our cash requirements could become significant. Fortunately, we now have a number of options with regard to future development. While we could now sell our position for a considerable profit, it is more likely that we would either reduce our interest for an up-front carried working interest in several wells or participate to our interest in newly proposed operations.

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.

We may alter or vary all, or part, of these contemplated activities based upon changes in circumstances, unforeseen opportunities, inability to negotiate favorable acquisition, farmout, joint venture or loan terms, lack of cash flow, lack of funding and/or other events which we are not able to anticipate.

Divestitures/Abandonments

During the quarter ended December 31, 2007 we began work to plug and abandon one operated and two non-operated wells.

RESULTS OF OPERATIONS

Nine Months Ended December 31, 2007 Compared to Nine Months Ended December 31, 2006

Overview. Net income for the nine months ended December 31, 2007 (2007) was $1,529,000 compared to net income of $1,775,000 for the nine months ended December 31, 2006 (2006), a decrease of 14%.

Revenues. Oil and gas sales revenue declined $128,000 (2%) in 2007 from 2006. Oil sales revenue increased $54,000 (1%). A negative variance from lower sales volumes was more than offset by higher oil prices. Gas sales revenue decreased $182,000 (24%) in 2007 from 2006. In this case, a positive variance from slightly higher gas prices was more than offset by a negative variance from lower sales volumes.

Volumes and Prices. Oil sales volumes declined 14%, from 79,600 barrels in 2006 to 68,300 barrels in 2007 while there was an 18% increase in the average price per barrel from $60.76 in 2006 to $71.61 in 2007. The drop in oil sales volume can be attributed mainly to expected production declines from our Richland County, Montana Bakken producers. Gas sales volume declined 27%, from 120.1 million cubic feet (MMcf) in 2006 to 88.1 MMcf in 2007, while the average price per Mcf rose 4%, from $6.35 in 2006 to $6.60 in 2007. The drop in

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gas sales volume is primarily due to production declines from our Antenna Federal property in Weld County, Colorado. As discussed in the Capital Expenditures section above, we have begun a 16-well drilling program on this property to take advantage of a new rule that allows for 20-acre spacing in the Wattenburg field. On an equivalent barrel (BOE) basis, sales volume declined 17% from 99,600 BOE in 2006 to 83,000 BOE in 2007.

Expenses. Oil and gas production expense increased $114,000 (8%) in 2007 over 2006. 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.

Routine lease operating expense increased $90,000 (8%) from $1,121,000 in 2006 to $1,211,000 in 2007 while workover expense increased $24,000 (8%) from $283,000 in 2006 to $307,000 in 2007. Routine lease operating expense per BOE increased 30% from $11.25 in 2006 to $14.59 in 2007 while workover expense per BOE rose 30% from $2.84 in 2006 to $3.70 in 2007.

Production taxes, which are generally a percentage of sales revenue, increased $85,000 (22%) in 2007 over 2006. Production taxes, as a percent of sales revenue rose from 6.8 percent in 2006 to 8.5 percent in 2007 as a result of the elimination of certain Montana tax incentives that were allowed during the first two years of production after new wells were drilled and completed. The overall lifting cost per BOE increased 33% from $17.89 in 2006 to $23.87 in 2007.

Depreciation and depletion expense increased $81,000 (18%) in 2007 over 2006 as a result of an increase in the full cost pool depletable base.

General and administrative expense increased $113,000 (28%) in 2007 over 2006. Increases in the number of office personnel, as well as additional expenses associated with the expansion of our board of directors and related compensation plan were only partially offset by a decrease in employee benefits and consulting fees. G&A expense per BOE increased 54% from $4.07 in 2006 to $6.25 in 2007. As a percent of total sales revenue, G&A expense rose from 7.2% in 2006 to 9.5% in 2007.

Quarter Ended December 31, 2007 Compared to Quarter Ended December 31, 2006

Overview. Net income for the quarter ended December 31, 2007 (2007) was $562,000 compared to net income of $278,000 for the quarter ended December 31, 2006 (2006), an increase of 102%.

Revenues. Oil and gas sales revenue increased $501,000 (32%) in 2007 from 2006. Oil sales revenue increased $577,000 (43%). A negative variance from lower sales volumes was more than offset by higher oil prices. Gas sales revenue declined $76,000 (32%) in 2007 from 2006. A positive variance from higher gas prices was more than offset by a negative variance from lower sales volumes.

Volumes and Prices. Oil sales volumes declined 9%, from 25,600 barrels in 2006 to 23,200 barrels in 2007 while there was a 57% jump in the average price per barrel from $52.48 in 2006 to $82.62 in 2007. Oil sales volumes again were negatively impacted by expected production declines from our Richland County, Montana Bakken producers. Gas sales volumes dropped 39%, from 38.5 MMcf in 2006 to 23.5 MMcf in 2007, while the average price per Mcf increased 11%, from $6.09 in 2006 to $6.76 in 2007. The drop in gas

11

sales volumes again is primarily due to production declines from our Antenna Federal property in Weld County, Colorado. On an equivalent barrel (BOE) basis, sales volumes decreased 15% from 32,000 BOE in 2006 to 27,200 BOE in 2007.

Expenses. Oil and gas production expense increased $65,000 (13%) in 2007 over 2006. Routine lease operating expense increased $31,000 (8%) from $396,000 in 2006 to $427,000 in 2007 while workover expense rose $34,000 (34%) from $100,000 in 2006 to $134,000 in 2007. Routine lease operating expense per BOE increased 27% from $12.37 in 2006 to $15.71 in 2007 while workover expense per BOE rose 58% from $3.12 in 2006 to $4.92 in 2007.

Production taxes, which are typically a percentage of sales revenue, increased $67,000 (59%) in 2007 over 2006. Production taxes, as a percent of sales revenue climbed from 7.1 percent in 2006 to 8.6 percent in 2007, again as a result of the elimination of certain Montana tax incentives. The overall lifting cost per BOE increased 43% from $19.01 in 2006 to $27.24 in 2007.

Depreciation and depletion expense increased $30,000 (21%) in 2007 over 2006 as a result of an increase in the full cost pool.

G&A expense increased $63,000 (48%) in 2007 over 2006 as a result of expenses associated with an increase in the number of office personnel and expansion of our board of directors and related compensation plan. G&A expense per BOE rose 75% from $4.10 in 2006 to $7.19 in 2007. G&A expense as a percent of total sales revenue increased from 8.3% in 2006 to 9.4% in 2007.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable and that actual results will not vary significantly from the estimated amounts. We believe the following accounting policies and estimates are critical in the preparation of our consolidated financial statements: the carrying value of its oil and gas property, the accounting for oil and gas reserves and the estimate of its asset retirement obligations.

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 and results in lower depreciation and depletion in future periods. The write-down may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.

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Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs, if any, related to the recorded value of our oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves attributable to these properties. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate 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 often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Ninety-two percent and eighty-eight percent of our reported oil and gas reserves at March 31, 2007 and December 31, 2007, respectively, are based on estimates prepared by an independent petroleum engineering firm. The remaining eight and twelve percent, respectively, of our oil and gas reserves were prepared in-house.

Asset Retirement Obligations. We have significant 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.

OFF BALANCE SHEET TRANSACTIONS, ARRANGEMENTS OR OBLIGATIONS

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

RECENT ACCOUNTING PRONOUNCEMENTS

On April 1, 2007 we adopted Financial Accounting Standard Board (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, 2007 we made no provisions for interest or penalties related to uncertain tax positions.

In September 2006 the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (SFAS No. 157). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. As of December 1, 2007 the FASB has proposed a one-year deferral for the implementation of SFAS No. 157 for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value in the financial statements on a non-recurring basis. The adoption of SFAS No. 157 is not expected to have a material impact on our financial position, results of operations or cash flow.

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In February 2007 the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 15 (SFAS No. 159). This statement permits companies to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of SFAS No. 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. SFAS No. 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. SFAS No. 159 will be effective for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159 is not expected to have a material impact on our financial position, results of operations or cash flows.

Liquids and Natural Gas Production, Sales Price and Production Costs

The following table shows selected financial information for the nine months and 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				Quarters Ended
	December 31				December 31
	2007		2006		2007		2006
Sales volume
Oil (barrels)		68,300		79,600		23,200		25,600
Gas (mcf)		88,100		120,100		23,500		38,500
Revenue
Oil	$	4,891,000	$	4,837,000	$	1,921,000	$	1,344,000
Gas		581,000		763,000		159,000		235,000
		5,472,000		5,600,000		2,080,000		1,579,000
Total production expense1		1,981,000		1,782,000		741,000		609,000
Gross profit	$	3,491,000	$	3,818,000	$	1,339,000	$	970,000
Depletion expense4	$	523,000	$	443,000	$	172,000	$	142,000
Average sales price2
Oil (per barrel)	$	71.61	$	60.76	$	82.62	$	52.48
Gas (per mcf)	$	6.60	$	6.35	$	6.76	$	6.09
Average production expense1,2,3	$	23.87	$	17.89	$	27.24	$	19.01
Average gross profit2,3	$	42.08	$	38.32	$	49.31	$	30.28
Average depletion expense2,3	$	6.30	$	4.44	$	6.34	$	4.44
Average general and administrative expense2,3	$	6.25	$	4.07	$	7.19	$	4.10

1	Operating expenses, including production tax
2	Averages calculated based upon non-rounded figures
3	Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)
4	Excluding impairment expense related to Canadian full cost pool ceiling limitation

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ITEM 3.
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.

As of December 31, 2007 Basic carried out an evaluation, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial 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 second quarter of the current fiscal year that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II.

OTHER INFORMATION

(Cumulative from March 31, 2007)

Item 1. Legal Proceedings

None.

Item 2. Changes in Securities

None.

Item 3. Defaults Upon Senior Securities

None.

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

On January 21, 2008 the Company held its Annual Meeting of Shareholders to elect four directors to its Board of Directors. In the election of directors, each nominee was elected by a vote of the shareholders as follows:

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Director	For	Withheld
David Flake	9,834,525	1,176,756
Monroe W. Robertson	9,841,063	1,170,218
Richard Rodgers	9,841,327	1,169,954
Ray Singleton	9,855,265	1,156,016

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

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

Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.

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.
 

/s/ Ray Singleton  

Ray Singleton 

President and Chief Executive Officer 

/s/ David Flake  

David Flake 

Chief Financial Officer and Principal Accounting Officer 

Date: February 12, 2008

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EXHIBIT INDEX

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

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