Basic Earth Science Sys, Inc - Recent Material Event

		September 30				March 31
		2007				2007
		(Unaudited)				(Audited)
Assets
Current assets:
Cash and cash equivalents		$	3,641,000			$	2,523,000
Accounts receivable:
Oil and gas sales			994,000				825,000
Joint interest and other receivables, net			429,000				436,000
Other current assets			268,000				262,000
Total current assets			5,332,000				4,046,000
Oil and gas property, full cost method:
Proved property			28,012,000				27,686,000
Unproved property			1,248,000				1,199,000
Accumulated depreciation and depletion			(18,193,000	)			(17,842,000	)
Net oil and gas property			11,067,000				11,043,000
Other non-current assets, net			375,000				363,000
Total non-current assets			11,442,000				11,406,000
Total Assets		$	16,774,000			$	15,452,000

See accompanying notes to consolidated financial statements.

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

		September 30				March 31
		2007				2007
		(Unaudited)				(Audited)
Liabilities
Current liabilities:
Accounts payable		$	360,000			$	744,000
Accrued liabilities			1,574,000				1,245,000
Total current liabilities			1,934,000				1,989,000
Long-term liabilities:
Deferred tax liability			986,000				581,000
Asset retirement obligation			1,805,000				1,802,000
Total long-term liabilities			2,791,000				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; 17,329,752 shares issued at September 30 and 17,304,752 at March 31			17,000				17,000
Additional paid-in capital			22,732,000				22,730,000
Accumulated deficit			(10,677,000	)			(11,644,000	)
Treasury stock (349,565 shares at September 30 and 349,265 March 31); at cost			(23,000	)			(23,000	)
Total shareholders’ equity			12,049,000				11,080,000
Total Liabilities and Shareholders’ Equity		$	16,774,000			$	15,452,000

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

		Six Months Ended								Quarters Ended
		September 30								September 30
		2007				2006				2007				2006
Revenue
Oil and gas sales		$	3,392,000			$	4,021,000			$	1,789,000			$	2,048,000
Well service revenue			16,000				25,000				5,000				14,000
Total revenue			3,408,000				4,046,000				1,794,000				2,062,000
Expenses
Oil and gas production			957,000				908,000				463,000				438,000
Production tax			283,000				265,000				157,000				143,000
Well service expenses			17,000				28,000				6,000				16,000
Depreciation and depletion			356,000				305,000				179,000				153,000
Accretion of asset retirement obligation			48,000				39,000				21,000				14,000
Asset retirement expense			19,000				94,000				2,000				80,000
General and administrative			323,000				273,000				155,000				123,000
Total operating expenses			2,003,000				1,912,000				983,000				967,000
Income from operations			1,405,000				2,134,000				811,000				1,095,000
Other income (expense)
Interest and other income			75,000				9,000				42,000				8,000
Interest and other expenses			(8,000	)			(6,000	)			(8,000	)			—
Total other income			67,000				3,000				34,000				8,000
Income before income taxes			1,472,000				2,137,000				845,000				1,103,000
Current income tax expense			100,000				27,000				50,000				10,000
Provision for deferred taxes			405,000				613,000				240,000				313,000
Total income taxes			505,000				640,000				290,000				323,000
Net income		$	967,000			$	1,497,000			$	555,000			$	780,000
Net income per share:
Basic		$	.057			$	.089			$	.033			$	.046
Diluted		$	.056			$	.087			$	.032			$	.045
Weighted average common shares outstanding:
Basic			16,964,503				16,789,913				16,973,665				16,799,237
Diluted			17,132,679				17,129,038				17,132,144				17,128,125

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

		Six Months Ended
		September 30
		2007				2006
Cash flows from operating activities:
Net income		$	967,000			$	1,497,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion			356,000				305,000
Deferred tax liability			405,000				613,000
Accretion of asset retirement obligation			48,000				39,000
Change in:
Accounts receivable, net			(162,000	)			123,000
Other assets			3,000				(327,000	)
Accounts payable and accrued liabilities			(100,000	)			55,000
Other			5,000				4,000
Net cash provided by operating activities			1,522,000				2,309,000
Cash flows from investing activities:
Capital expenditures:
Oil and gas property			(383,000	)			(808,000	)
Support equipment			(5,000	)			(21,000	)
Insurance settlement			—				161,000
Proceeds from sale of oil and gas property and equipment			6,000				—
Other			(24,000	)			7,000
Net cash used in investing activities			(406,000	)			(661,000	)
Cash flows from financing activities:
Proceeds from exercise of common stock options			2,000				3,000
Proceeds from borrowing			—				565,000
Long-term debt payments			—				(1,010,000	)
Net cash provided by (used in) financing activities			2,000				(442,000	)
Cash and cash equivalents:
Net increase			1,118,000				1,206,000
Balance at beginning of period			2,523,000				78,000
Balance at end of period		$	3,641,000			$	1,284,000
Supplemental disclosure of cash flow information:
Cash paid for interest		$	6,000			$	6,000
Cash paid for oil and gas property		$	159,000			$	704,000

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

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.

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 statement 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 six months ended September 30, 2007 we recorded income tax expense of $505,000. This includes a current year expense of $100,000 and a deferred tax provision of $405,000. 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.

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 September 30, 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 November 7, 2007.

Working Capital. At September 30, 2007 we had a working capital surplus of $3,398,000 (a current ratio of 2.76:1) 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 September 30 is primarily a result of our improved cash position.

Cash Flow. Net cash provided by operating activities dropped 34% from $2,309,000 in the six months ended September 30, 2006 to $1,522,000 in the six months ended September 30, 2007. This decrease was primarily due to declining sales volumes, as well as a $440,000 negative variance from the change in accounts payable and accrued liabilities.

Net cash used in investing activities dropped 39% from $661,000 in 2006 to $406,000 in 2007. This decline is merely a matter of timing with respect to the various projects discussed in the Contemplated Activities section below.

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 six months ended September 30, 2007 and at September 30, 2007 we had no open futures, forwards or option contracts in place to hedge future production.

CAPITAL EXPENDITURES

During the quarter ended September 30, 2007, we spent approximately $336,000 on various projects. When combined with first quarter investments, we have deployed $383,000 through the first six months of the current fiscal year. This compares to $217,000 and $808,000 for the quarter and six months ended September 30, 2006, respectively. Through the first six months of fiscal 2008, approximately $271,000 (70%) of expenditures were dedicated to our Antenna Federal development drilling project in Weld County, Colorado while drilling and completion efforts on our interest in the TR Madison Unit, in Billings County, North Dakota accounted for an additional $27,000 (7%).

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 program that will last until mid-January 2008. While the majority of wells will be drilled to the Codell formation, at least four wells will be drilled to the deeper J-Sand formation. We expect to have a 15% working interest in the Codell wells and a 30% to 60% working interest in J-Sand production (depending on actual well location). Completion and production testing is not expected to commence until after drilling operations have been finished. We expect to spend $1.7 million for our share of the cost of drilling and completing these wells. Kerr-McGee Oil & Gas Onshore, LP will be the operator of the project.

In Montana, the Company and its 50% partner expect to drill a vertical Red River test on the South Flat Lake prospect in fiscal 2008. 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.

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; one of which may be started as early as this December. 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.

We have received notification from our partners that they expect to hydraulically stimulate the Lynn #3 in the Indian Hill field at the end of November 2007. This well has never been stimulated beyond an initial acid clean-up and is currently pumping 20 barrels of oil per day from the Mission Canyon formation. We have an approximate 20% working interest and expect to spend $60,000 on this procedure. If successful, we anticipate a similar effort on the Lynn #2.

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. Most recently, ConocoPhillips has staked four wells west of our western boundary; one of which is currently drilling. If these wells are successful, the viability of the Bakken formation in our Banks Prospect should become more attractive.

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.

Oil and Gas Reserves

During the quarter ended September 30, 2007, with respect to the re-completion of an existing well and the on-going drilling program on our Antenna Federal property in Weld County, Colorado, we added proved oil and gas reserves of $934,000. This is the estimated future pre-tax net cash flows discounted at 10%. Total estimated future production from these reserves is 29,000 barrels of oil and 210 million cubic feet of gas.

Divestitures/Abandonments

During the quarter ended September 30, 2007 we did not plug and abandon or sell any wells or properties.

RESULTS OF OPERATIONS

Six Months Ended September 30, 2007 Compared to Six Months Ended September 30, 2006

Overview. Net income for the six months ended September 30, 2007 (2007) was $967,000 compared to net income of $1,497,000 for the six months ended September 30, 2006 (2006), a decrease of 35%.

Revenues. Oil and gas sales revenue decreased $629,000 (16%) in 2007 from 2006. Oil sales revenue decreased $523,000 (15%). A positive variance from higher oil prices was more than offset by lower sales volumes. Gas sales revenue decreased $106,000 (20%) in 2007 from 2006. Again, 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 16%, from 54,000 barrels in 2006 to 45,100 barrels in 2007 while there was a 2% increase in the average price per barrel from $64.69 in 2006 to $65.92 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 21%, from 81.6 million cubic feet (MMcf) in 2006 to 64.6 MMcf in 2007, while the average price per Mcf rose 1%, from $6.47 in 2006 to $6.54 in 2007. The drop in 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 67,600 BOE in 2006 to 55,800 BOE in 2007.

Expenses. Oil and gas production expense increased $49,000 (5%) 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 $59,000 (8%) from $725,000 in 2006 to $784,000 in 2007 while workover expense decreased $10,000 (6%) from $183,000 in 2006 to $173,000 in 2007. Routine lease operating expense per BOE increased 31% from $10.72 in 2006 to $14.05 in 2007 while workover expense per BOE rose 14% from $2.72 in 2006 to $3.10 in 2007.

Production taxes, which are generally a percentage of sales revenue, increased $18,000 (7%) in 2007 over 2006. Production taxes, as a percent of sales revenue rose from 6.6 percent in 2006 to 8.4 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 28% from $17.36 in 2006 to $22.22 in 2007.

Depreciation and depletion expense increased $51,000 (17%) in 2007 over 2006 as a result of an increase in the full cost pool depletable base.

General and administrative expense increased $50,000 (18%) in 2007 over 2006. Increases in SEC reporting and audit-related expenses, as well as additional expenses associated with expansion of our board of directors and related compensation plan were only partially offset by a decrease in employee benefits. G&A expense per BOE increased 43% from $4.05 in 2006 to $5.79 in 2007. As a percent of total sales revenue, G&A expense rose from 6.8% in 2006 to 9.5% in 2007.

Quarter Ended September 30, 2007 Compared to Quarter Ended September 30, 2006

Overview. Net income for the quarter ended September 30, 2007 (2007) was $555,000 compared to net income of $780,000 for the quarter ended September 30, 2006 (2006), a decrease of 29%.

Revenues. Oil and gas sales revenue decreased $259,000 (13%) in 2007 from 2006. Oil sales revenue decreased $145,000 (8%). A positive variance from higher oil prices was more than offset by lower sales volumes. Gas sales revenue decreased $114,000 (40%) in 2007 from 2006 as a result of both lower sales volumes and natural gas prices.

Volumes and Prices. Oil sales volumes declined 15%, from 26,900 barrels in 2006 to 22,800 barrels in 2007 while there was an 8% increase in the average price per barrel from $65.56 in 2006 to $70.95 in 2007. Oil sales volumes again were negatively impacted by expected production declines from our Richland County, Montana Bakken producers. Gas sales volumes dropped 31%, from 44.1 MMcf in 2006 to 30.4 MMcf in 2007, while the average price per Mcf decreased 12%, from $6.49 in 2006 to $5.69 in 2007. The drop in gas 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 19% from 34,200 BOE in 2006 to 27,800 BOE in 2007.

Expenses. Oil and gas production expense increased $25,000 (6%) in 2007 over 2006. Routine lease operating expense increased $31,000 (9%) from $359,000 in 2006 to $390,000 in 2007 while workover expense dropped $6,000 (8%) from $79,000 in 2006 to $73,000 in 2007. Routine lease operating expense per BOE increased 34% from $10.49 in 2006 to $14.05 in 2007 while workover expense per BOE rose 13% from $2.30 in 2006 to $2.61 in 2007.

Production taxes, which are typically a percentage of sales revenue, increased $14,000 (10%) in 2007 over 2006. Production taxes, as a percent of sales revenue climbed from 7.0 percent in 2006 to 8.8 percent in 2007, again as a result of the elimination of certain Montana tax incentives. The overall lifting cost per BOE increased 31% from $16.98 in 2006 to $22.26 in 2007.

Depreciation and depletion expense increased $26,000 (17%) in 2007 over 2006 as a result of an increase in the full cost pool.

G&A expense increased $32,000 (26%) in 2007 over 2006 as a result of expenses associated with expansion of our board of directors and related compensation plan. G&A expense per BOE rose 55% from $3.60 in 2006 to $5.57 in 2007. G&A expense as a percent of total sales revenue increased from 6.0% in 2006 to 8.7% 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.

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 September 30, 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.

(Intentionally left blank.)

Liquids and Natural Gas Production, Sales Price and Production Costs

The following table shows selected financial information for the six months and quarter ended September 30 in the current and prior year. Certain prior year amounts may have been reclassified to conform to current year presentation.

		Six Months Ended								Quarters Ended
		September 30								September 30
		2007				2006				2007				2006
Sales volume
Oil (barrels)			45,100				54,000				22,800				26,900
Gas (mcf)			64,600				81,600				30,400				44,100
Revenue
Oil		$	2,970,000			$	3,493,000			$	1,617,000			$	1,762,000
Gas			422,000				528,000				172,000				286,000
			3,392,000				4,021,000				1,789,000				2,048,000
Total production expense1			1,240,000				1,173,000				620,000				581,000
Gross profit		$	2,152,000			$	2,848,000			$	1,169,000			$	1,467,000
Depletion expense4		$	351,000			$	301,000			$	177,000			$	151,000
Average sales price2
Oil (per barrel)		$	65.92			$	64.69			$	70.95			$	65.56
Gas (per mcf)		$	6.54			$	6.47			$	5.69			$	6.49
Average production expense1,2,3		$	22.22			$	17.36			$	22.26			$	16.98
Average gross profit2,3		$	38.56			$	42.13			$	42.00			$	42.87
Average depletion expense2,3		$	6.28			$	4.45			$	6.36			$	4.41
Average general and administrative expense2,3		$	5.79			$	4.05			$	5.57			$	3.60

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 September 30, 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

During the six months ended September 30, 2007 there were no meetings of our shareholders nor were any matters submitted to a vote of security holders through the solicitation of consents, proxies or otherwise.

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