UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended JuneSeptember 30, 2008

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.

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 AugustNovember 14, 2008: 17,465,585


BASIC EARTH SCIENCE SYSTEMS, INC.
FORM 10-Q
INDEX

 PART I. FINANCIAL INFORMATIONPage
   
Item 1.
Financial Statements
3
Consolidated Balance Sheets:
    June 30, 2008 (Unaudited) and March 31, 2008
3
   
 
    Consolidated Statements of OperationsBalance Sheets:
 
     September 30, 2008 (Unaudited) and March 31, 20083
   Consolidated Statements of Income:
Three and Six Months Ended JuneSeptember 30, 2008 and 2007 (Unaudited)5
   
 
    Consolidated Statements of Cash Flows:
 
 
    Three    Six Months Ended JuneSeptember 30, 2008 and 2007 (Unaudited)
6
   
 
    Notes to Unaudited Consolidated Financial Statements:
 
 
    June    September 30, 2008 (Unaudited)
7
   
Item 2.
Management’s Discussion and Analysis and Plan of Operation
11
   
 
    Results of Operations
13
   
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
1517
   
Item 4.
Controls and Procedures
1517
   
 PART II. OTHER INFORMATION 
   
Item 1.
Legal Proceedings
1618
   
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
1618
   
Item 3.
Defaults Upon Senior Securities
1618
   
Item 4.
Submission of Matters to a Vote of Security Holders
1618
   
Item 5.
Other Information
1618
   
Item 6.
Exhibits
1618
   
 
Signatures
1719
 
2
 

PART I– FINANCIAL INFORMATION

Item 1. Financial Statements

Basic Earth Science Systems, Inc.
Consolidated Balance Sheets
Page 1 of 2

 June 30,  March 31,  September 30, March 31, 
 2008  2008  2008 2008 
 (Unaudited)     (Unaudited)   
Assets           
Current assets:           
Cash and cash equivalents $4,593,000  $5,571,000  $5,754,000  $5,571,000 
Accounts receivable:             
Oil and gas sales  1,789,000   1,110,000   1,737,000   1,110,000 
Joint interest and other receivables, net of $41,000 and $50,000 in allowance  563,000   236,000   574,000   236,000 
Other current assets  317,000   280,000   286,000   280,000 
             
Total current assets  7,262,000   7,197,000   8,351,000   7,197,000 
             
Oil and gas property, full cost method:             
Proved property  31,042,000   29,050,000   31,306,000   29,050,000 
Unproved property  1,268,000   2,515,000   1,268,000   2,515,000 
Accumulated depletion  (18,727,000)  (18,515,000)  (18,916,000)  (18,515,000)
             
Net oil and gas property  13,583,000   13,050,000   13,658,000   13,050,000 
             
Support equipment and other non-current assets, net of $313,000 and $299,000 in accumulated depreciation, respectively  437,000   443,000 
Support equipment and other non-current assets, net of $322,000 and $299,000 in accumulated depreciation, respectively  425,000   443,000 
             
Total non-current assets  14,020,000   13,493,000   14,083,000   13,493,000 
             
Total assets $21,282,000  $20,690,000  $22,434,000  $20,690,000 

See accompanying notes to unaudited consolidated financial statements.

3

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

 June 30,  March 31,  September 30, March 31, 
 2008  2008  2008 2008 
 (Unaudited)     (Unaudited)   
Liabilities and Shareholders' Equity           
Current liabilities:           
Accounts payable $780,000  $1,443,000  $291,000  $1,443,000 
Accrued liabilities  1,982,000   2,586,000   2,599,000   2,586,000 
             
Total current liabilities  2,762,000   4,029,000   2,890,000   4,029,000 
             
Long-term liabilities:             
Deferred tax liability  3,215,000   2,800,000   3,365,000   2,800,000 
Asset retirement obligation  1,941,000   1,877,000   1,869,000   1,877,000 
             
Total long-term liabilities  5,156,000   4,677,000   5,234,000   4,677,000 
             
Total liabilities  7,918,000   8,706,000   8,124,000   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 17,465,585 shares issued and outstanding  17,000   17,000 
Shareholders’ Equity:     
Preferred stock, $.001 par value, 3,000,000 authorized, none issued or outstanding  —   — 
Common stock, $.001 par value, 32,000,000 shares authorized, 17,465,585 shares issued and outstanding  17,000   17,000 
Additional paid-in capital  22,798,000   22,798,000   22,798,000   22,798,000 
Treasury stock (349,265 shares); at cost  (23,000)  (23,000)  (23,000)  (23,000)
Accumulated deficit  (9,428,000)  (10,808,000)  (8,482,000)  (10,808,000)
             
Total shareholders’ equity  13,364,000   11,984,000   14,310,000   11,984,000 
             
Total liabilities and shareholders’ equity $21,282,000  $20,690,000  $22,434,000  $20,690,000 

See accompanying notes to unaudited consolidated financial statements.

4

Basic Earth Science Systems, Inc.
Consolidated Statements of OperationsIncome
(Unaudited)

  Six Months Ended  Three Months Ended 
  September 30,  September 30, 
  2008  2007  2008  2007 
      (As restated)      (As restated) 
Revenues:                
     Oil and gas sales $6,009,000  $3,392,000  $2,697,000  $1,789,000 
     Well service and water disposal revenue  45,000   16,000   38,000   5,000 
                 
Total revenues  6,054,000   3,408,000   2,735,000   1,794,000 
                 
Expenses:                
     Oil and gas production  1,129,000   957,000   563,000   463,000 
     Production tax  498,000   283,000   216,000   157,000 
     Well servicing expenses  53,000   17,000   44,000   6,000 
     Depreciation and depletion  418,000   356,000   197,000   179,000 
     Accretion of asset retirement obligation  36,000   48,000   23,000   21,000 
     Asset retirement expense  129,000   19,000   175,000   2,000 
     General and administrative  558,000   323,000   255,000   155,000 
                 
Total expenses  2,821,000   2,003,000   1,473,000   983,000 
                 
Income from operations  3,233,000   1,405,000   1,262,000   811,000 
                 
Other Income (Expense):                
     Interest and other income  42,000   75,000   34,000   42,000 
     Interest and other expenses  (16,000)   (8,000)   (13,000)   (8,000) 
                 
Total other income  26,000   67,000   21,000   34,000 
                 
Income before income taxes  3,259,000   1,472,000   1,283,000   845,000 
                 
Current income tax expense  368,000   100,000   187,000   50,000 
Provision for deferred income taxes  565,000   655,000   150,000   365,000 
                 
Total income taxes  933,000   755,000   337,000   415,000 
                 
Net income $2,326,000  $717,000  $946,000  $430,000 
                 
Per share amounts:                
     Basic $0.13  $0.04  $0.05  $0.03 
     Diluted $0.13  $0.04  $0.05  $0.03 
                 
Weighted average common shares outstanding:                
     Basic  17,465,585   16,964,503   17,465,585   16,973,665 
     Diluted  17,502,071   17,132,679   17,502,071   17,132,144 
  Three Months Ended 
  June 30, 
  2008 2007 
    (As restated) 
Revenues:      
     Oil and gas sales $3,312,000  $1,603,000 
     Well service revenue  7,000   11,000 
         
Total revenues  3,319,000   1,614,000 
         
Expenses:        
     Oil and gas production  566,000   494,000 
     Production tax  282,000   126,000 
     Well servicing expenses  9,000   11,000 
     Depreciation and depletion  221,000   177,000 
     Accretion of asset retirement obligation  13,000   27,000 
     Asset retirement expense  (46,000)  17,000 
     General and administrative  303,000   168,000 
         
Total expenses  1,348,000   1,020,000 
         
Income from operations  1,971,000   594,000 
         
Other Income (Expense):        
     Interest and other income  8,000   33,000 
     Interest and other expenses  (3,000)  ― 
         
Total other income  5,000   33,000 
         
Income before income taxes  1,976,000   627,000 
         
Current income tax expense  181,000   50,000 
Deferred income tax expense  415,000   290,000 
         
Total income tax expense  596,000   340,000 
         
Net income $1,380,000  $287,000 
         
Per share amounts:        
     Basic $0.08  $0.02 
     Diluted $0.08  $0.02 
         
Weighted average common shares outstanding:        
     Basic  17,465,585   16,955,240 
     Diluted  17,468,898   17,133,137 

See accompanying notes to unaudited consolidated financial statements.

5


Basic Earth Science Systems, Inc.
Consolidated Statements of Cash Flows
(Unaudited)

 Three Months Ended  Six Months Ended 
 June 30,  September 30, 
  2008  2007   2008  2007 
 (As restated)  (As restated) 
Cash flows from operating activities:          
Net income $1,380,000 $287,000  $2,326,000 $717,000 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:          
Depreciation and depletion 221,000 177,000  418,000 356,000 
Deferred tax expense 415,000 290,000 
Deferred tax liability 565,000 655,000 
Accretion of asset retirement obligation 13,000 27,000  36,000 48,000 
Change in:          
Accounts receivable, net (1,006,000) 162,000  (965,000) (162,000) 
Other assets (48,000) 24,000  (13,000) 3,000 
Accounts payable and accrued liabilities (122,000) (387,000)  484,000 (100,000) 
Other  —  2,000   ―  5,000 
          
Net cash provided by operating activities  853,000  582,000   2,851,000  1,522,000 
          
Cash flows from investing activities:          
Oil and gas property (1,839,000) (47,000)  (2,668,000) (383,000) 
Support equipment 8,000 (2,000)  ― (5,000) 
Proceeds from sale of oil and gas property and equipment ― 6,000  ― 6,000 
Other  ―  (7,000)   ―  (24,000) 
          
Net cash used in investing activities  (1,831,000)  (50,000)   (2,668,000)  (406,000) 
          
Cash flows from financing activities:     
Proceeds from exercise of common stock options  ―  2,000 
     
Net cash provided by financing activities  ―  2,000 
     
Cash and cash equivalents:          
Increase in cash and cash equivalents (978,000) 532,000  183,000 1,118,000 
Balance, beginning of year  5,571,000  2,523,000   5,571,000  2,523,000 
          
Balance, end of year $4,593,000 $3,055,000  $5,754,000 $3,641,000 
          
Supplemental disclosure of cash flow information:          
Cash paid for interest $3,000 $―  $5,000 $6,000 
Cash paid for income tax $50,000 $―  $205,000 $― 
Non-cash:          
Increase in oil and gas property due to asset retirement obligation $13,000 $―  $32,000 $3,000 
Additions to oil and gas property also included in accrued liabilities $642,000 $― 

See accompanying notes to unaudited consolidated financial statements.

6

Basic Earth Science Systems, Inc.
Notes to Unaudited Consolidated Financial Statements
JuneSeptember 30, 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 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, 2008.

Forward-Looking Statements

This Form 10-Q 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-Q, 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, 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-Q.

1. Presentation of Condensed Consolidated Financial Statements

As discussed in our 2008 Annual Report on Form 10-KSB, 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 recently filed Annual Report on Form 10-KSB for the fiscal year ended March 31, 2008.

7
 
The following table summarizes the impact of these corrections to our consolidated  condensed statement of operationsincome for the fiscal quarter ending as of JuneSeptember 30, 2007, as previously presented in Footnote 13 – Quarterly Financial Data (Unaudited) of our Annual Report on Form 10-KSB. 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 Six Months ended September 30, 2007  Three Months ended September 30, 2007 
(Unaudited) As reported  Adjustment  As restated  As reported  Adjustment  As restated 
                   
Provision for deferred income taxes $405,000  $250,000  $655,000  $240,000  $125,000  $365,000 
Total income taxes  505,000   250,000   755,000   290,000   125,000   415,000 
                         
Net Income $967,000  $(250,000) $717,000  $555,000  $(125,000) $430,000 
                         
Per share amounts:                        
Basic $0.06  $(0.02) $0.04  $0.03  $(0.00) $0.03 
Diluted $0.06  $(0.02) $0.04  $0.03  $(0.00) $0.03 
Impact to the Income Statement Three Months ended June 30, 2007 
(Unaudited) As reported  Adjustment  As restated 
          
Provision for deferred income taxes $165,000  $125,000  $290,000 
Total income taxes  215,000   125,000   340,000 
             
Net Income $412,000  $(125,000) $287,000 
             
Per share amounts:            
     Basic $0.02  $(0.00)  $0.02 
     Diluted $0.02  $(0.00)  $0.02 

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, and the estimate of our income tax assets and liabilities.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 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. As of September 30, 2008, we determined that our capitalized costs did not exceed the ceiling test limit.

8
 
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-five percent and eighty-seven percent of our reported oil and gas reserves at March 31, 2008 and JuneSeptember 30, 2008, respectively, are based on estimates prepared by an independent petroleum engineering firm. The remaining five and thirteen percent, respectively, of our oil and gas reserves were prepared in-house.

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 operations;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.

  Six Months Ended 
  September 30, 2008 
     
Balance beginning of period $2,179,000 
     Liabilities incurred  32,000 
     Liabilities settled  (142,000)
     Revisions in estimated cash flows  (3,000)
     Accretion expense  36,000 
Balance end of period $2,102,000 

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.

9
 
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 JuneSeptember 30, 2008, we made no provisions for interest or penalties related to uncertain tax positions.
9
 
Earnings Per Share. Our earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share 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,income, 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 doesdid not have a material effect on our financial position, results of operations,income, or cash flows.

10


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 the provisions of SFAS No. 157 doesdid not have a material effectimpact on our financial position, results of operations,income, or cash flows.
In July 2006,  Beginning April 1, 2009, we expect to adopt the FASB issued FIN No. 48, “Accountingprovisions for Uncertaintynon-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 Income Taxes — An Interpretationthe process of SFAS 109”. FIN 48 clarifiesevaluating this standard with respect to its effect on non- financial assets and liabilities, we have not yet determined the accounting for uncertainty in income taxes recognized in an enterprise’simpact that it will have on our financial statements upon full adoption in accordance2009.

3. Subsequent Events

On October 30, 2008, Basic Earth Science Systems, Inc. (the "Company") announced its plan to repurchase up to 500,000 shares of common stock, par value $0.01 per share of the Company. The plan allows purchases to be made from time to time in the open market and through privately negotiated transactions in compliance with SFAS 109, “Accounting for Income Taxes”Rules 10b5-1 and 10b-18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). FIN 48 also prescribes a recognition threshold and measurement attribute forRule 10b5-1 permits the financial statement recognition and measurementimplementation of a tax position takenwritten plan for repurchasing or expectedselling Company stock at times when the Company is not in possession of material, non-public information and allows issuers adopting such plans to be takenrepurchase shares on a regular basis, regardless of any subsequent material, non-public information it receives or the price of the stock at the time of the purchase. Rule 10b-18 is a "safe harbor" rule, which allows issuers to repurchase shares of their own stock in the public market, subject to compliance with particular repurchase requirements. 

Subsequent to the period ended September 30, 2008, we acquired a 1.5625% working interest (1.250% net revenue interest) in a tax return. In addition, FIN 48 provides guidancesecond Dunn County, horizontal Bakken well operated by Marathon Oil Company. This well, the Steffan 14-22H, is currently flowing approximately 300 barrels of oil per day on derecognition, classification, interesta 14/64" choke and penalties, accounting in interim periods, disclosureis still recovering completion fluids. We estimate that we spent approximately $100,000 on the acquisition of leasehold rights and transition. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized as an adjustment to the opening balance of retained earnings (or other appropriate components of equity) for that fiscal year. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We adopted FIN 48 effective April 1, 2007. See Note 9, Income Taxes, for further discussion.

subsequent drilling and completion costs.
10
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. In addition, as mentioned in the “Bank Debt”“Credit Line” section below, we currently have $4,000,000 of unused borrowing capacity.

Working Capital. At JuneSeptember 30, 2008, we had a working capital surplus of $4,500,000$5,461,000 (a current ratio of 2.63:2.89:1) 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 increases in price and production of oil and gas duringfor the quarterperiod ended JuneSeptember 30, 2008.


11
Cash Flow. Net cash provided by operating activities increased 47%87% from $582,000$1,522,000 in the quartersix months ended JuneSeptember 30, 2007 (“2007”) to $853,000$2,851,000 in the quartersix months ended JuneSeptember 30, 2008 (“2008”). This increase was primarily due to increased oil and gas revenue, and accounts receivable, offset primarily by increasesan increase in depletion and deferred taxes.depletion.

Net cash used in investing activities increased 3,562%557% from $50,000$406,000 during 2007 to $1,831,000$2,668,000 in the quartersix months ended JuneSeptember 30, 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.

Credit Line. Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Effective January 3, 2006 we amended the existing loan agreement to increase the line of credit amount from $1,000,000 to $20,000,000 with a concurrent borrowing base increase from $1,000,000 to $4,000,000. Effective December 31, 2006 the loan agreement was amended again to extend the maturity date of the credit agreement to December 31, 2008.

During the year ended March 31, 2008, we utilized none of our credit facility. Our effective annual interest rate at JuneSeptember 30, 2008 was WSJ prime plus 0.25%. On JuneSeptember 30, 2008, we had no outstanding principal balance on the line of credit with the entire $4,000,000 available for borrowing. If necessary, we may borrow 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

During the quarter ended June 30, 2008 (2008), we estimate that, on an accrual basis, we spent $640,000 (net of $118,000 in plugging and abandonment costs) on various projects compared to $47,000 for the same period in 2007.  During 2008 our capital expenditures were primarily focused in the DJ Basin of Colorado where 82% of these funds were invested.  These projects were funded with internally generated cash flow from operations.  TheseThe amounts arepresented herein 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 and not on an accrual basis as stated above.basis.

During the quarter ended September 30, 2008, we spent approximately $575,000 on various projects.  When combined with first quarter investments, we have deployed $1,215,000 through the first six months of the current fiscal year.  This compares to $336,000 and $383,000 for the quarter and six months ended September 30, 2007, respectively. Through the first six months of fiscal 2008, approximately 78% of capital expenditures were dedicated to drilling and completions, 13% was dedicated to preservation of expiring leases and 9% was dedicated to the acquisition of producing properties.

During the quarter ended September 30, 2008, we estimate that we spent 55% of our drilling and completion dollars on our Antenna Federal development drilling project in Weld County, 19% on drilling and completing the newest Marathon operated well, the Steffan 14-22H, and 19% on the TR Madison Unit in Billings County, North Dakota.  These projects were funded with internally generated cash flow from operations.

Contemplated Activities

We anticipate pursuing the following activities during the remainder of fiscal 2009.

Panther Energy Company, LLC. (Panther) is drilling the first of two wells on 13,000 gross acres in our Banks prospect in McKenzie County, North Dakota.  Basic has a 6.5% (32.5% of 20%) carried working interest “to the tanks” on the Banks acreage contributed to the spacing unit for the first two wells and the right to participate for 6.5% interest on the Banks acreage contributed to the spacing unit in subsequent wells.  As previously disclosed, until Panther finishes these first two wells, Panther’s continued involvement  or our timing to participate in subsequent wells remains undetermined.

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In Montana, we and our 50% partner expect to drill a vertical Red River test on the South Flat Lake prospect in the fourth quarter of fiscal 2009 or first quarter of 2010, depending on weather and road conditions.  If successful, it is possible that as many as 4 development wells could be drilled.  As previously disclosed, efforts to commence drilling this fall were initially hampered by the lack of available drilling rigs and more recently by the scarcity of casing in the grades and weights that we require. We are continually evaluating exploration, developmenthave purchased casing that is expected to be delivered in late February which will free us to begin drilling efforts then.  The initial well is expected to cost approximately $1.35 million to drill.  While we now own and acquisition opportunitiescould participate for our 50% interest in an effortthis prospect, if we and our partner sell a portion of this prospect as intended, our interest would be proportionately reduced. We expect to grow our oil and gas reserves. be the operator of this property.

At present cash flow levels, and further 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.  However, we may alter or vary all or part of these planned capital expenditures based upon changes in circumstances, unforeseen opportunities, inability to negotiate favorable acquisition, farmout or joint venture terms, lack of cash flow, lack of additional funding, if necessary, and/or other events which we are not able to anticipate.

Contemplated Activities

In addition to the discussion in Capital Expenditures described above, we anticipate pursuing the following activities during the remainder of fiscal 2009.

As previously disclosed, we are concluding a year-long, sixteen well 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 52.5% 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 has been installed and at this time all of the wells are up and running. 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 second 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 $1.35 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 June 2005 quarter, we acquired a 20% interest in 13,000 acres in our Banks prospect in McKenzie County, North Dakota.  While initial efforts were discouraging, during the intervening period, the success of new techniques by various companies has given new life to the area.  After evaluating several proposals, we and our partners have executed a farmout agreement with an unrelated, private, third-party.  Under the terms of this agreement, the third party will drill two horizontal Bakken wells on the Banks acreage and carry us and our partners for a 32.5% carried working interest “to the tanks”.  In exchange, the third party will earn 67.5% interest in all of our Banks acreage.  After the first two wells have been drilled, Basic will have the right to participate in subsequent wells for our 32.5% working interest (proportionately reduced to our original 20% working interest or approximately 6.5%, and subject to proportionate reduction based on contributed acreage within a specific drilling spacing unit).  Based on assurances received from the third party, we expect drilling operations to commence within 60 to 90 days.
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.

12
Divestitures/Abandonments

During the quarter ended JuneSeptember 30, 2008 we completed plugging one operated well which began in the prior quarter.  
 
Results of Operations

Three Months Ended JuneSeptember 30, 2008 Compared to Three Months Ended JuneSeptember 30, 2007

Overview. Net income for the three months ended JuneSeptember 30, 2008 (“2008”) was $1,380,000$946,000 compared to net income of $287,000,$430,000, as restated, for the three months ended JuneSeptember 30, 2007, (“2007”), an increase of 381%120%.

Revenues. Oil and gas sales revenue increased $1,703,000 (106%$908,000 (51%) net of $6,000 in water disposal revenue in 2008 from 2007. Oil sales revenue increased $1,519,000 (112%$617,000 (38%), and gas sales revenue increased $184,000 (74%$291,000 (169%) in 2008 from 2007.  These increases resulted largely from the overall increased price during the quarter.quarter, as well as the recently completed DJ wells.

Volumes and Prices. Oil sales volumes increased 7%decreased 15%, from 22,30022,800 barrels in 2007 to 23,90019,400 barrels in 2008 while there was an increase of 98%62% in the average price per barrel from $60.77$70.95 in 2007 to $120.11$115.09 in 2008. The drop in oil sales volume is attributed primarily to a reversal of over accrued volume estimates made in the previous quarter that were associated with our new wells on our Antenna Federal property in Weld County, Colorado.  Gas sales volume increased 26%28% from 34.230.4 million cubic feet (MMcf) in 2007 to 43.138.8 MMcf in 2008, while the average price per Mcf increased 38%111%, from $7.30$5.69 in 2007 to $10.08$11.98 in 2008. The increase in gas sales volume is primarily due to bringing offlineback online wells in the Antenna Federal property in Weld County, Colorado, back online, as well as the production of new wells in the same property. On an equivalent barrel (BOE) basis, sales volume increased 11%decreased 7% from 28,00027,800 BOE in 2007 to 31,00025,900 BOE in 2008.


13
Expenses. Oil and gas production expense increased $72,000 (15%$100,000 (22%) 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 59,000 (15%$95,000 (24%) from $394,000$390,000 in 2007 to $453,000$485,000 in 2008 while workover expense increased $13,000 (13%$5,000 (7%) from $100,000$73,000 in 2007 to $113,000$78,000 in 2008. Routine lease operating expense per BOE decreased 1%increased 34% from $14.07$14.05 in 2007 to $14.61$18.73 in 2008 while workover expense per BOE increased 1%16% from $3.57$2.61 in 2007 to $3.65$3.01 in 2008.

Production taxes, which are generally a percentage of sales revenue, increased $156,000 (124%$59,000 (38%) in 2008 over 2007 primarily due to the influence of higher oil prices and understandably higher gross revenues. Production taxes, as a percent of sales revenue stayed consitent atdecreased from 9% in 2007 to 8% in 2007 and 2008.  The overall lifting cost (oil and gas production expense and production taxes) per BOE increased 23%35% from $22.19$22.26 in 2007 to $27.27$30.07 in 2008.
 
Depreciation and depletion expense increased $44,000 (25%$18,000 (10%) in 2008 over 2007 as a result of an increase in the full cost pool depletable base.
 
With respectGeneral and administrative expense increased $100,000 (65%) in 2008 over 2007. These increases were primarily the result of increased expenditures attributable to asset retirement obligations,the restatement of our financials, along with increases in consulting fees, and to a less extent, increases in the number of office personnel.  G&A expense per BOE increased 77% from $5.57 in 2007 to $9.85 in 2008. As a percent of total sales revenue, G&A expense remained consistent at 9% from 2007 to 2008.

Six Months Ended September 30, 2008 Compared to Six Months Ended September 30, 2007

Overview. Net income for the six months ended September 30, 2008 was $2,326,000 compared to net income of $717,000 as restated for the six months ended September 30, 2007, an increase of 224%.

Revenues. Oil and gas sales revenue increased $2,617,000 (77%) in 2008 from 2007. Oil sales revenue increased $2,137,000 (72%). Gas sales revenue increased $481,000 (114%) in 2008 from 2007. These increases resulted largely from the increased price during the quarter just ended, we experiencedpast six months.

Volumes and Prices. Oil sales volumes declined 4%, from 45,100 barrels in 2007 to 43,300 barrels in 2008 while there was a net gain79% increase in the average price per barrel from $65.92 in 2007 to $117.86 in 2008. Gas sales volume increased 27%, from 64.6 million cubic feet (MMcf) in 2007 to 81.9 MMcf in 2008, while the average price per Mcf rose 68%, from $6.54 in 2007 to $10.98 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 2% from 55,800 BOE in 2007 to 57,000 BOE in 2008.

Expenses. Oil and gas production expense increased $172,000 (18%) in 2008 over 2007. Oil and gas production expense is comprised of $46,000two 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 is reflected as a negative asset retirement expense. This treatment is consistent with our existing accounting policies.
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 $154,000 (20%) from $784,000 in 2007 to $938,000 in 2008 while workover expense increased $18,000 (10%) from $173,000 in 2007 to $191,000 in 2008. Routine lease operating expense per BOE increased 17% from $14.05 in 2007 to $16.46 in 2008 while workover expense per BOE rose 8% from $3.10 in 2007 to $3.35 in 2008.

Production taxes, which are generally a percentage of sales revenue, increased $215,000 (76%) in 2008 over 2007. Production taxes, as a percent of sales revenue remained consistent at 8% from 2007 to 2008. The overall lifting cost (oil and gas production expense and production taxes) per BOE increased 28% from $22.22 in 2007 to $28.54 in 2008.

Depreciation and depletion expense increased $62,000 (17%) in 2008 over 2007 as a result of an increase in the full cost pool depletable base.

General and administrative expense increased $135,000 (80%$235,000 (73%) in 2008 over 2007. IncreasesThese increases were primarily the result of increased expenditures attributable to the restatement of our financials, along with increases in consulting fees, and to a less extent, increases in the number of office personnel and consultants, as well as additional expenses associated with the expansion of our board of directors and related compensation plan.personnel. G&A expense per BOE increased 63%69% from $6.00$5.79 in 2007 to $9.77$9.79 in 2008. However, asAs a percent of total sales revenue, G&A expense decreaseddeclined from 10% in 2007 to 9% in 2008.

Income Tax Expense. For the threesix months ended JuneSeptember 30, 2008 we recorded income tax expense of $415,000.$933,000. This includes a current year expense of $596,000$368,000 and a deferred tax provision of $243,000.$565,000.  Our effective income tax rate decreased from 54.2%51.3% for the quartersix months ended JuneSeptember 30, 2007 to 30.0%28.6% for 2008. Our effective income tax rate was lower for 2008 primarily due to an increase in estimated deductions for statutory depletion.


15
Liquids and Natural Gas Production, Sales Price and Production Costs

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

 Six Months Ended Three Months Ended 
 Three Months Ended  September 30, September 30, 
 June 30, 2008  2008 2007 2008 2007 
 2008 2007          
Sales volume:              
Oil (barrels) 23,911 22,300   43,300   45,100   19,400   22,800 
Gas (mcf) 43,072 34,200   81,900   64,600   38,800   30,400 
              
Revenue:              
Oil $2,872,000 $1,353,000  $5,106,000  $2,970,000  $2,234,000  $1,617,000 
Gas  434,000  250,000   903,000   422,000   463,000   172,000 
Total revenue1
 3,306,000 1,603,000   6,009,000   3,392,000   2,697,000   1,789,000 
              
Total production expense2
  848,000  620,000   1,627,000   1,240,000   779,000   620,000 
              
Gross profit $2,458,000 $983,000  $4,382,000  $2,152,000  $1,918,000  $1,169,000 
              
Depletion expense $221,000 $174,000  $400,000  $351,000  $179,000  $177,000 
              
Average sales price3
              
Oil (per barrel) $120 $61  $117.86  $65.92  $115.09  $70.95 
Gas (per mcf) $10 $7  $10.98  $6.54  $11.98  $5.69 
Average production expense2,3,4
 $27 $22  $28.54  $22.22  $30.13  $22.26 
Average gross profit3,4
 $79 $35  $76.88  $38.56  $74.05  $42.00 
Average depletion expense3,4
 $7 $6  $7.33  $6.28  $7.61  $6.36 
Average general and administrative expense3,4
 $10 $6  $9.79  $5.79  $9.85  $5.57 

1 Net of $6,000$45,000 in water disposal revenue, as compared to total revenues of $3,312,000$6,054,000
2 OperatingOverall lifting cost (oil and gas production expenses includingand production taxtaxes)
3 Averages calculated based upon non-rounded figures
4 Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)
 
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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 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 partiallyto 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 JuneSeptember 30, 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 JuneSeptember 30, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II– OTHER INFORMATION

Item 1.1. Legal Proceedings

None.

Item 2.2. Unregistered Sales of Equity Securities and Use of Proceeds

On April 1, 2008, pursuant to the terms of Restricted Stock Agreements dated April 7, 2007, two of our directors became fully vested in 7,571 shares of our common stock, each. Based on a price of $1.585 on the date of grant, these shares serve as partial compensation to our independent directors for services performed during the past fiscal year at an aggregate fair value of $12,000 each.None.

In connection with the award and vesting of the subject shares, we relied upon the exemption from federal registration under Section 4(2) of the Securities Act of 1933, as amended, based on our belief that the issuance of such shares did not involve a public offering. In executing the Restricted Stock Agreement, each director acknowledged that he has such knowledge and experience in financial and business matters so that he was capable of evaluating the risks of the investment. Any certificates evidencing the subject shares shall contain a restrictive investment legend noted thereon.

Item 3.3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit No. Document
   
31.1
 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer).
   
31.2
 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).
   
32.1
 Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer).
   
32.2
 Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).

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.

1618

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.  
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: AugustNovember 14, 2008