EARTHSTONE ENERGY INC - Quarter Report: 2008 November (Form 10-Q)

e10q_9-08.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended September 30, 2008

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

Commission file number: 0-7914

BASIC EARTH SCIENCE SYSTEMS, INC.

633 Seventeenth St, Suite 1645

Denver, Colorado 80202-3625

Telephone (303) 296-3076

Incorporated in Delaware

IRS ID# 84-0592823

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company þ

Check whether the issuer is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

Shares of common stock outstanding on November 14, 2008: 17,465,585

Table of Contents

BASIC EARTH SCIENCE SYSTEMS, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION	Page

Item 1.	Financial Statements	3

	Consolidated Balance Sheets:
	September 30, 2008 (Unaudited) and March 31, 2008	3

	Consolidated Statements of Income:
	Three and Six Months Ended September 30, 2008 and 2007 (Unaudited)	5

	Consolidated Statements of Cash Flows:
	Six Months Ended September 30, 2008 and 2007 (Unaudited)	6

	Notes to Unaudited Consolidated Financial Statements:
	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	17

Item 4.	Controls and Procedures	17

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	18

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	18

Item 3.	Defaults Upon Senior Securities	18

Item 4.	Submission of Matters to a Vote of Security Holders	18

Item 5.	Other Information	18

Item 6.	Exhibits	18

	Signatures	19

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 1 of 2

	September 30,			March 31,
	2008			2008
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	5,754,000		$	5,571,000
Accounts receivable:
Oil and gas sales		1,737,000			1,110,000
Joint interest and other receivables, net of $41,000 and $50,000 in allowance		574,000			236,000
Other current assets		286,000			280,000

Total current assets		8,351,000			7,197,000

Oil and gas property, full cost method:
Proved property		31,306,000			29,050,000
Unproved property		1,268,000			2,515,000
Accumulated depletion		(18,916,000	)		(18,515,000	)

Net oil and gas property		13,658,000			13,050,000

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		14,083,000			13,493,000

Total assets	$	22,434,000		$	20,690,000

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 2 of 2

	September 30,			March 31,
	2008			2008
	(Unaudited)
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	291,000		$	1,443,000
Accrued liabilities		2,599,000			2,586,000

Total current liabilities		2,890,000			4,029,000

Long-term liabilities:
Deferred tax liability		3,365,000			2,800,000
Asset retirement obligation		1,869,000			1,877,000

Total long-term liabilities		5,234,000			4,677,000

Total liabilities		8,124,000			8,706,000

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
Treasury stock (349,265 shares); at cost		(23,000	)		(23,000	)
Accumulated deficit		(8,482,000	)		(10,808,000	)

Total shareholders’ equity		14,310,000			11,984,000

Total liabilities and shareholders’ equity	$	22,434,000		$	20,690,000

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

Basic Earth Science Systems, Inc.

Consolidated Statements of Income

(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

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	September 30,
		2008		2007
			(As restated)
Cash flows from operating activities:
Net income	$	2,326,000	$	717,000
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and depletion		418,000		356,000
Deferred tax liability		565,000		655,000
Accretion of asset retirement obligation		36,000		48,000
Change in:
Accounts receivable, net		(965,000)		(162,000)
Other assets		(13,000)		3,000
Accounts payable and accrued liabilities		484,000		(100,000)
Other		―		5,000

Net cash provided by operating activities		2,851,000		1,522,000

Cash flows from investing activities:
Oil and gas property		(2,668,000)		(383,000)
Support equipment		―		(5,000)
Proceeds from sale of oil and gas property and equipment		―		6,000
Other		―		(24,000)

Net cash used in investing activities		(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		183,000		1,118,000
Balance, beginning of year		5,571,000		2,523,000

Balance, end of year	$	5,754,000	$	3,641,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	5,000	$	6,000
Cash paid for income tax	$	205,000	$	―
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	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.

Table of Contents

Basic Earth Science Systems, Inc.

Notes to Unaudited Consolidated Financial Statements

September 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 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 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.

Table of Contents

The following table summarizes the impact of these corrections to our consolidated statement of income for the fiscal quarter ending as of September 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

2. Summary of Significant Accounting Policies and Recent Accounting Pronouncements

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the actual amounts of assets and liabilities at the date of the financial statements and the actual amounts of revenues and expenses during the reporting period. We base these estimates on assumptions that we understand are reasonable under the circumstances. The estimated results that are produced by this effort will differ under different assumptions or conditions. We understand that these estimates are necessary and that actual results could vary significantly from the estimated amounts for the current and future periods. There are many factors, including global events, which may influence the production, processing, marketing, and valuation of crude oil and natural gas. A reduction in the valuation of oil and gas properties resulting from declining prices or production could adversely impact depletion rates and ceiling test limitations. We understand the following accounting policies and estimates are necessary in the preparation of our consolidated financial statements: the carrying value of our oil and gas property, the accounting for oil and gas reserves, the estimate of our asset retirement obligations, the estimate of our income tax assets and liabilities and estimates of accrued quantities and prices in our oil and gas receivable.

Cash and Cash Equivalents. For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, we consider all highly liquid investments with a maturity of ninety days or less when purchased to be cash equivalents.

Oil and Gas 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.

Table of Contents

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 September 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 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.

Table of Contents

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, 2008, we made no provisions for interest or penalties related to uncertain tax positions.

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 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 did not have a material effect on our financial position, results of income, or cash flows.

Table of Contents

In September 2006, the FASB issued SFAS Statement No. 157, “Fair Value Measurements”. SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued Staff Position No. FAS 157-2. That guidance proposed a one year deferral of the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).

On April 1, 2008, we adopted SFAS No. 157 with the one-year deferral for non-financial assets and liabilities. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of income, or cash flows. Beginning April 1, 2009, we expect to adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. While we are in the process of evaluating this standard with respect to its effect on non- financial assets and liabilities, we have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

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 Rules 10b5-1 and 10b-18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Rule 10b5-1 permits the implementation of a written plan for repurchasing or selling Company stock at times when the Company is not in possession of material, non-public information and allows issuers adopting such plans to repurchase 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 second 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 a 14/64" choke and is still recovering completion fluids. We estimate that we spent approximately $100,000 on the acquisition of leasehold rights and subsequent drilling and completion costs.

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 “Credit Line” section below, we currently have $4,000,000 of unused borrowing capacity.

Working Capital. At September 30, 2008, we had a working capital surplus of $5,461,000 (a current ratio of 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 for the period ended September 30, 2008.

Table of Contents

Cash Flow. Net cash provided by operating activities increased 87% from $1,522,000 in the six months ended September 30, 2007 (“2007”) to $2,851,000 in the six months ended September 30, 2008 (“2008”). This increase was primarily due to increased oil and gas revenue, offset primarily by an increase in depletion.

Net cash used in investing activities increased 557% from $406,000 during 2007 to $2,668,000 in the six months ended September 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 September 30, 2008 was WSJ prime plus 0.25%. On September 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

The amounts presented 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.

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.

Table of Contents

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 have 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 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.

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.

We are continually evaluating other drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of due diligence. Our policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken. We caution that the absence of news and/or press releases should not be interpreted as a lack of development or activity.

Divestitures/Abandonments

During the quarter ended September 30, 2008 we completed plugging one operated well which began in the prior quarter.

Results of Operations

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

Overview. Net income for the three months ended September 30, 2008 was $946,000 compared to net income of $430,000, as restated, for the three months ended September 30, 2007, an increase of 120%.

Revenues. Oil and gas sales revenue increased $908,000 (51%) in 2008 from 2007. Oil sales revenue increased $617,000 (38%), and gas sales revenue increased $291,000 (169%) in 2008 from 2007. These increases resulted largely from the overall increased price during the quarter, as well as the recently completed DJ wells.

Volumes and Prices. Oil sales volumes decreased 15%, from 22,800 barrels in 2007 to 19,400 barrels in 2008 while there was an increase of 62% in the average price per barrel from $70.95 in 2007 to $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 28% from 30.4 million cubic feet (MMcf) in 2007 to 38.8 MMcf in 2008, while the average price per Mcf increased 111%, from $5.69 in 2007 to $11.98 in 2008. The increase in gas sales volume is primarily due to bringing back online wells in the Antenna Federal property in Weld County, Colorado, as well as the production of new wells in the same property. On an equivalent barrel (BOE) basis, sales volume decreased 7% from 27,800 BOE in 2007 to 25,900 BOE in 2008.

Table of Contents

Expenses. Oil and gas production expense increased $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 $95,000 (24%) from $390,000 in 2007 to $485,000 in 2008 while workover expense increased $5,000 (7%) from $73,000 in 2007 to $78,000 in 2008. Routine lease operating expense per BOE increased 34% from $14.05 in 2007 to $18.73 in 2008 while workover expense per BOE increased 16% from $2.61 in 2007 to $3.01 in 2008.

Production taxes, which are generally a percentage of sales revenue, increased $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 decreased from 9% in 2007 to 8% in 2008. The overall lifting cost (oil and gas production expense and production taxes) per BOE increased 35% from $22.26 in 2007 to $30.07 in 2008.

Depreciation and depletion expense increased $18,000 (10%) in 2008 over 2007 as a result of an increase in the full cost pool depletable base.

General and administrative expense increased $100,000 (65%) in 2008 over 2007. These 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. 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 past 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 79% 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 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.

Table of Contents

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 $235,000 (73%) in 2008 over 2007. These 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. G&A expense per BOE increased 69% from $5.79 in 2007 to $9.79 in 2008. As a percent of total sales revenue, G&A expense declined from 10% in 2007 to 9% in 2008.

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

Table of Contents

Liquids and Natural Gas Production, Sales Price and Production Costs

The following table shows selected financial information for the 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				Three Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Sales volume:
Oil (barrels)		43,300		45,100		19,400		22,800
Gas (mcf)		81,900		64,600		38,800		30,400

Revenue:
Oil	$	5,106,000	$	2,970,000	$	2,234,000	$	1,617,000
Gas		903,000		422,000		463,000		172,000
Total revenue1		6,009,000		3,392,000		2,697,000		1,789,000

Total production expense2		1,627,000		1,240,000		779,000		620,000

Gross profit	$	4,382,000	$	2,152,000	$	1,918,000	$	1,169,000

Depletion expense	$	400,000	$	351,000	$	179,000	$	177,000

Average sales price3
Oil (per barrel)	$	117.86	$	65.92	$	115.09	$	70.95
Gas (per mcf)	$	10.98	$	6.54	$	11.98	$	5.69
Average production expense2,3,4	$	28.54	$	22.22	$	30.13	$	22.26
Average gross profit3,4	$	76.88	$	38.56	$	74.05	$	42.00
Average depletion expense3,4	$	7.33	$	6.28	$	7.61	$	6.36
Average general and administrative expense3,4	$	9.79	$	5.79	$	9.85	$	5.57

1		Net of $45,000 in water disposal revenue, as compared to total revenues of $6,054,000
2		Overall lifting cost (oil and gas production expenses and production taxes)
3		Averages calculated based upon non-rounded figures
4		Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)

Table of Contents

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 to a large extent determined by factors beyond our control.

Item 4. Controls and Procedures

The Company maintains a system of disclosure controls and procedures that are designed for the purpose of ensuring that information required to be disclosed in its SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

For the quarter ended September 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 September 30, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

None.

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

None.

Item 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.

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed by the following authorized persons on behalf of Basic.


BASIC EARTH SCIENCE SYSTEMS, INC.

By: /s/ Ray Singleton
Ray Singleton
President and Chief Executive Officer

By: /s/ Joseph Young
Joseph Young
Principal Accounting Officer

Date: November 14, 2008