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

e10q_6-09.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 June 30, 2009

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 August 12, 2009: 17,544,893

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BASIC EARTH SCIENCE SYSTEMS, INC.

FORM 10-Q

INDEX

	PART I. FINANCIAL INFORMATION	Page

Item 1.	Financial Statements	4

	Consolidated Balance Sheets:
	June 30, 2009 (Unaudited) and March 31, 2009	4

	Consolidated Statements of Operations:
	Three Months Ended June 30, 2009 and 2008 (Unaudited)	6

	Consolidated Statements of Cash Flows:
	Three Months Ended June 30, 2009 and 2008 (Unaudited)	7

	Notes to Unaudited Consolidated Financial Statements:
	June 30, 2009 (Unaudited)	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	17

Item 4T.	Controls and Procedures	17

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	18

Item 1A.	Risk Factors	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	19

	Signatures	20

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FORWARD-LOOKING STATEMENTS

This Current Report on Form 10-Q, including information incorporated herein by reference, contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "plan," "should" or similar expressions are intended to identify such statements. Forward-looking statements relate to, among other things:

• our future financial position, including anticipated liquidity;

• amounts and nature of future capital expenditures;

• acquisitions and other business opportunities;

• operating costs and other expenses;

• wells expected to be drilled;

• asset retirement obligations; and

• estimates of proved oil and natural gas reserves, deferred tax liabilities, and depletion rates.

Factors that could cause actual results to differ materially from our expectations include, among others, such things as:

• oil and natural gas prices;

• our ability to replace oil and natural gas reserves;

• loss of senior management or technical personnel;

• inaccuracy in reserve estimates and expected production rates;

• exploitation, development and exploration results;

• the actual costs related to asset retirement obligations, and whether or not those retirements actually occur in the future;

• a lack of available capital and financing;

• the potential unavailability of drilling rigs and other field equipment and services;

• the existence of unanticipated liabilities or problems relating to acquired properties;

• general economic, market or business conditions;

• factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment,

permitting issues, workovers, and weather;

• the impact and costs related to compliance with or changes in laws or regulations governing our oil and natural gas operations;

• environmental liabilities;

• acquisitions and other business opportunities (or the lack thereof) that may be presented to and pursued by us;

• competition for available properties and the effect of such competition on the price of those properties;

• risk factors discussed in this report; and

• other factors, many of which are beyond our control.

Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. Disclosure of important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2009, under the heading "Risk Factors", and elsewhere in this report, including, without limitation, in conjunction with the forward-looking statements. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 1 of 2

	June 30,			March 31,
	2009			2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	4,054,000		$	4,088,000
Accounts receivable:
Oil and gas sales		2,130,000			1,611,000
Joint interest and other receivables, net of $71,000 and $71,000 in allowance, respectively		181,000			230,000
Other current assets		508,000			508,000

Total current assets		6,873,000			6,437,000

Oil and gas property, full cost method:
Proved property		32,500,000			32,187,000
Unproved property		1,076,000			1,077,000
Accumulated depletion and impairment		(22,627,000	)		(22,397,000	)

Net oil and gas property		10,949,000			10,867,000

Support equipment and other non-current assets, net of $346,000 and $337,000 in accumulated depreciation, respectively		461,000			458,000

Total non-current assets		11,410,000			11,325,000

Total assets	$	18,283,000		$	17,762,000

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

Page 2 of 2

	June 30,			March 31,
	2009			2009
	(Unaudited)
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	377,000		$	64,000
Accrued liabilities		1,421,000			1,328,000

Total current liabilities		1,798,000			1,392,000

Long-term liabilities:
Deferred tax liability		2,290,000			2,242,000
Asset retirement obligation		1,490,000			1,558,000

Total long-term liabilities		3,780,000			3,800,000

Total liabilities		5,578,000			5,192,000

Commitments (within note 2)

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 17,545,000 and 17,506,000 shares issued and outstanding, respectively		18,000			18,000
Additional paid-in capital		22,873,000			22,825,000
Treasury stock (587,000 and 380,000 shares, respectively); at cost		(205,000	)		(43,000	)
Accumulated deficit		(9,981,000	)		(10,230,000	)

Total shareholders’ equity		12,705,000			12,570,000

Total liabilities and shareholders’ equity	$	18,283,000		$	17,762,000

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

(Unaudited)

		Three Months Ended
		June 30,
		2009			2008

Revenues:
Oil and gas sales	$	1,460,000		$	3,306,000
Well service and water disposal revenue		16,000			13,000

Total revenues		1,476,000			3,319,000

Expenses:
Oil and gas production		468,000			566,000
Production tax		120,000			282,000
Well servicing expenses		15,000			9,000
Depreciation and depletion		238,000			221,000
Accretion of asset retirement obligation		42,000			13,000
Asset retirement expense (gain)		4,000			(46,000	)
General and administrative		335,000			303,000

Total expenses		1,222,000			1,348,000

Income from operations		254,000			1,971,000

Other income (expense):
Interest and other income		―			8,000
Interest and other expenses		(15,000	)		(3,000	)

Total other income (expense)		(15,000	)		5,000

Income before income taxes		239,000			1,976,000

Income taxes:
Current income tax (benefit) expense		(58,000	)		181,000
Provision for deferred income taxes		48,000			415,000

Total income tax (benefit) expense		(10,000	)		596,000

Net income	$	249,000		$	1,380,000

Per share amounts:
Basic	$	0.01		$	0.08
Diluted	$	0.01		$	0.08

Weighted average common shares outstanding:
Basic		17,510,907			17,465,585
Diluted		17,510,907			17,468,898

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	June 30,
		2009			2008

Cash flows from operating activities:
Net income	$	249,000		$	1,380,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		238,000			221,000
Deferred tax liability		48,000			415,000
Accretion of asset retirement obligation		42,000			13,000
Share based compensation		12,000			―
Change in:
Accounts receivable, net		(470,000	)		(1,006,000	)
Other assets		1,000			(48,000	)
Accounts payable and accrued liabilities		341,000			(122,000	)

Net cash provided by operating activities		461,000			853,000

Cash flows from investing activities:
Oil and gas property		(333,000	)		(1,831,000	)

Net cash used in investing activities		(333,000	)		(1,831,000	)

Cash flows from financing activities:
Purchase of treasury shares		(162,000	)		―

Net cash used in financing activities		(162,000	)		―

Cash and cash equivalents:
Decrease in cash and cash equivalents		(34,000	)		(978,000	)
Balance, beginning of year		4,088,000			5,571,000

Balance, end of period	$	4,054,000		$	4,593,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	10,000		$	3,000
Cash paid for income tax	$	―		$	50,000
Non-cash:
Increase (decrease) in oil and gas property due to asset retirement obligation	$	16,000		$	13,000
Vested shares issued as compensation	$	48,000		$	—
Additions to oil and gas also included in accrued liabilities	$	87,000		$	―

See accompanying notes to unaudited consolidated financial statements.

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Basic Earth Science Systems, Inc.

Notes to Unaudited Consolidated Financial Statements

June 30, 2009

1. Presentation of Consolidated Financial Statements

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 any applicable 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 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 related notes thereto included in our Annual Report on Form 10-K for the year ended March 31, 2009.

We have evaluated events subsequent to June 30, 2009 through August 12, 2009, the filing date of this report, and determined that there were no subsequent events to recognize or disclose in these consolidated financial statements which would either impact the results reflected in this report or the Company’s results going forward.

Organization and Nature of Operations. Basic Earth Science Systems, Inc. was originally organized in July 1969 and had its first public offering in 1980. We are principally engaged in the acquisition, exploitation, development, operation and production of crude oil and natural gas. Our primary areas of operation are the Williston basin in North Dakota and Montana, south Texas and the Denver-Julesburg basin in Colorado.

Principles of Consolidation. The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

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.

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Oil and Gas Reserves. Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. At March 31, 2009, ninety-eight percent of our reported oil and gas reserves are based on estimates prepared by Ryder Scott Company, L.P, a nationally recognized, independent petroleum engineering firm. The remaining two percent of our oil and gas reserves were prepared by our technical in-house staff.

Each quarter, we update reserve estimates by substituting the prices we would have received at quarter-end for the year-end prices that were used by our independent petroleum engineers. In conducting this “re-pricing” no changes are made to the decline rates, tax rates or lifting costs used by our independent petroleum engineers. The determinations of depletion expense, as well as the results of ceiling tests and corresponding write-downs, if any, are highly dependent on these reserve and quarterly “re-pricing” estimates.

Oil and Gas Sales. We derive revenue primarily from the sale of produced natural gas and crude oil. We report revenue on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded using the sales method, which occurs in the month production is delivered to the purchaser, at which time title changes hands. Payment is generally received between 30 and 90 days after the date of production. We make estimates of the amount of production delivered to purchasers and the prices we will receive. We use our knowledge of our properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received, or when better information is available.

Oil and Gas Property. We follow the full cost method of accounting for our oil and gas property. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. 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 using current prices and costs discounted at 10 percent plus the lower of cost or fair value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. As of June 30, 2009, our capitalized costs did not exceed the ceiling test limit.

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. The carrying amount of cash equivalents approximates fair value because of the short-term maturity of those instruments. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.

Support Equipment and Other. Support equipment (including such items as vehicles, office furniture and equipment and well servicing equipment) is stated at cost. Depreciation of support equipment and other property is computed using the straight-line method over periods ranging from five to seven years.

Inventory. Inventory, consisting primarily of tubular goods and oil field equipment, is stated at the lower of cost or market, cost being determined by the FIFO method.

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Long-Term Assets. We apply Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in evaluating all long-lived assets except the full cost pool for possible impairment. Under SFAS No. 144, long-lived assets are reported at the lower of cost or their estimated recoverable amounts. During 2009 and 2008, there was no impairment recorded for long-lived assets.

Fair Value Measurements. Effective April 1, 2009, we adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. Accordingly, the fair value is based on unobservable pricing inputs and therefore, is considered a level 3 value input in the fair value hierarchy.

Asset Retirement Obligations. We have obligations related to the plugging and abandonment of our oil and gas wells. 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 numerous and 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; 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 consolidated statement of operations as a component of asset retirement expense.

The information below reconciles the value of the asset retirement obligation for the period presented. This includes a short term obligation of $182,000, which is carried within the accrued liabilities line item of the balance sheet.

	Three Months Ended June 30, 2009

Balance beginning of period	$	1,698,000
Liabilities incurred		16,000
Liabilities settled		(3,000	)
Revisions to estimates		(81,000	)
Accretion expense		42,000

Balance end of period	$	1,672,000

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Commitments. We currently office in a 4,000 square foot office space located in downtown Denver, Colorado, and are committed to a total of $281,000 for the five-year lease term ending April 1, 2013. We have no off balance sheet transactions or arrangements.

Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial statements and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse.

Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, the net deferred tax liability is continually re-evaluated and numerous estimates are revised over time. As such, the net deferred tax liability may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves, and the depletion of these long-lived reserves.

On April 1, 2007 we adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48). The adoption of FIN 48 had no impact on our consolidated financial statements. We are subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are fiscal years 2006 through 2008. We recognize interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2009, we made no provisions for interest or penalties related to uncertain tax positions.

Earnings Per Share. Our earnings per share (EPS) is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted EPS is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options. As of the balance sheet date, no dilutive securities were outstanding.

Recent Accounting Pronouncements

In June 2009, The FASB issued SFAS 168, “Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162” (Codification) which will become the source of authoritative U.S. generally accepted accounting principles (GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. This statement supersedes SFAS 162 “The Hierarchy of Generally Accepted Accounting Principles.” The adoption of SFAS 168 will not have a material impact on our consolidated financial statements or results of operations.

In June 2009, the FASB issued SFAS No. 165, “Subsequent Events” which incorporates the subsequent events guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. SFAS No.165 is effective for all interim and annual periods ending after June 15, 2009. The Company adopted SFAS No.165 upon its issuance and it had no material impact on our consolidated financial statements.

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On April 29, 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to require publicly-traded companies, as defined in APB Opinion No. 28, “Interim Financial Reporting,” to provide disclosures on the fair value of financial instruments in interim financial statements. FSP SFAS 107-1 and APB 28-1 are effective for interim periods ending after June 15, 2009. We have adopted the provisions of FSP SFAS 107-1, which did not have a material impact on the Company’s consolidated financial statements or results of operations.

On April 9, 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. FSP SFAS 157-4 is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009. We have adopted the provisions of FSP 157-4, which did not have a material impact on our consolidated financial statements or results of operations.

On April 1, 2009, the FASB issued FSP 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP 141R-1). FSP 141R-1 amends and clarifies SFAS No. 141R to address application issues associated with initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP 141R-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will apply the provisions of FSP 141R-1 to future acquisitions.

In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements is a broader definition of reserves, which allows reporting of probable and possible reserves, in addition to consideration of new technologies and non-traditional resources. In addition, oil and gas reserves will be reported using an average price based on the prior 12-month period, rather than year-end prices, and allow companies to disclose their probable and possible reserves to investors. The new rules are expected to be effective for years ending on or after December 31, 2009. The Company is in the process of evaluating the effect of these new requirements, and has not yet determined the impact that it will have on its financial statements upon full adoption on March 31, 2010.

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. We will apply the provisions of SFAS 141R to future acquisitions.

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In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51.” SFAS 160 amends ARB 51 to establish accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB 51’s consolidation procedures for consistency with the requirements of SFAS 141R. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The statement shall be applied prospectively as of the beginning of the fiscal year in which the statement is initially adopted. We have adopted the provisions of SFAS 160 which did not have a material effect on our financial position, results of operations, or cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, providing companies with an option to report selected financial assets and liabilities at fair value. The Standard’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. Generally accepted accounting principles have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. SFAS 159 helps to mitigate this type of accounting-induced volatility by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with detailed rules for hedge accounting. 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 effective date of SFAS 159 for our Company is April 1, 2008. We have adopted the provisions of SFAS 159, and it did not have a material effect on our financial condition or results of operations as we did not make any such elections under this fair value option.

In September 2006, the FASB issued SFAS Statement No. 157, “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued Staff Position No. FAS 157-2. That guidance proposed a one year deferral of the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On April 1, 2008, we adopted SFAS No. 157 with the one-year deferral for non-financial assets and liabilities. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations, or cash flows. Beginning April 1, 2009, we have adopted 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. The adoption did not have a material impact on our financial statements.

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

Liquidity and Capital Resources

Liquidity Outlook. Our primary source of funding is the net cash flow from the sale of our oil and gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. Assuming that oil prices do not decline from current levels, we believe the cash generated from operations, along with existing cash balances, will enable us to meet our existing and normal recurring obligations during the next fiscal year and beyond.

Working Capital. At June 30, 2009, we had a working capital surplus of $5,075,000 (a current ratio of 3.82:1) compared to a working capital surplus at March 31, 2009 of $5,045,000 (a current ratio of 4.62:1). The decrease in current ratio is largely a result of the respective timing of payments made on the accounts payable balance near the end of March 31, 2009.

Cash Flow. Net cash provided by operating activities decreased 46.0% from $853,000 in the three months ended June 30, 2008 (“2008”) to $461,000 in the three months ended June 30, 2009 (“2009”) primarily due to decreased oil and gas commodity prices.

Net cash used in investing activities decreased 81.8% from $1,831,000 during 2008 to $333,000 in the three months ended June 30, 2009. The difference relates primarily to significantly more expenditures made during the prior year on the DJ Basin wells in Colorado.

Net cash used in financing activities was $162,000 at June 30, 2009 as compared to no cash used for financing activities at June 30, 2008 since the Company did not adopt its stock buyback program until October 2008.

Credit Line. Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Subject to evaluation every six months, the line of credit amount was set at $20,000,000 with a concurrent borrowing base of $4,000,000. Effective December 31, 2008 the loan agreement was amended to extend the maturity date of the credit agreement to December 31, 2010. We renewed the line with an interest rate of prime plus 0.25% or 6.5% whichever is higher. During the year ended March 31, 2009 and for the three months ending June 30, 2009, we did not utilize our credit facility. The loan contains several covenant restrictions. At June 30, 2009, we were in compliance with all covenants. This line may be used for purposes of borrowing funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions, or pursue other opportunities that might arise.

Capital Expenditures

The amounts presented herein are presented on an accrual basis, and as such may not be consistent with the amounts presented on the consolidated statement of cash flows under investing activities for expenditures on oil and gas property in that the amounts contained therein are presented on a cash basis.

During the quarter ended June 30, 2009, we spent approximately $377,000 on various projects. This compares to $640,000 for the quarter ended June 30, 2008.

During the quarter ended June 30, 2009, nearly 100% of capital expenditures were dedicated to drilling and completions. We spent approximately 38% of our capital expenditures amount on the Crown 41-31 project in McKenzie County, North Dakota, 12% on the Halvorsen 21X-36 in Richland County, Montana, and 50% on the Halvorsen State 31X-36 in Richland County, Montana. These projects were funded with internally generated cash flow from operations.

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At present cash levels, and with the extension of our available borrowing capacity, we expect to have sufficient funds available for our share of any additional acreage, seismic and/or drilling cost requirements that might arise from these opportunities. We may alter or vary all or part of these planned capital expenditures for reasons including but not limited to; changes in circumstances, unforeseen opportunities, inability to negotiate favorable acquisition, farmout or joint venture terms, lack of cash flow, and lack of additional funding.

We currently have no capital expenditure commitments. We are continually evaluating other drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of due diligence. Our policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken. We caution that the absence of news and/or press releases should not be interpreted as a lack of development or activity.

Divestitures/Abandonments

During the quarter ended June 30, 2009 we plugged no additional wells. Instead, all expenses incurred during the quarter were for surface restoration.

Results of Operations

Overview. Net income for the three months ended June 30, 2009 was $249,000 compared to net income of $1,380,000, for the three months ended June 30, 2008. The following table shows selected financial information for the quarter ended June 30 in the current and prior year. Certain prior year amounts may have been reclassified to conform to current year presentation.

	Three Months Ended
	June 30,
	2009		2008
	(Unaudited)		(Unaudited)
Sales volume
Oil (barrels)		24,343		23,911
Gas (mcf)		35,186		43,072

Revenue
Oil	$	1,270,000	$	2,872,000
Gas		190,000		434,000
Total revenue1		1,460,000		3,306,000

Total production expense2		588,000		848,000

Gross profit	$	872,000	$	2,458,000

Depletion expense	$	230,000	$	212,000
General and administrative expense		335,000		303,000

Average sales price3
Oil (per barrel)	$	52.17	$	120.11
Gas (per mcf)	$	5.40	$	10.08

Average per BOE
Production expense2,3,4	$	19.47	$	27.28
Gross profit3,4	$	28.87	$	79.06
Depletion expense3,4	$	7.61	$	6.82
General and administrative expense3,4	$	11.09	$	9.75

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1		Net of $16,000 in water service and disposal revenue, to total $1,476,000 in revenue for the three months ended June 30, 2009, compared to $13,000 to total $3,319,000 for the same period in 2008.
2		Overall lifting cost (oil and gas production expenses and production taxes)
3		Averages calculated based upon non-rounded figures
4		Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

Revenues. Oil and gas sales revenue decreased $1,846,000 (55.8%) in 2009 from 2008 due to lower realized oil and gas prices. Oil sales revenue decreased $1,602,000 (55.8%), and gas sales revenue decreased $244,000 (56.2%) in 2009 from 2008.

Volumes and Prices. Oil sales volumes increased 1.8%, from 23,911 barrels in 2008 to 24,343 barrels in 2009 while there was a decrease of 56.6% in the average price per barrel from $120.11 in 2008 to $52.17 in 2009. Gas sales volume decreased 18.3% from 43,072 thousand cubic feet (Mcf) in 2008 to 35,186 Mcf in 2009, while the average price per Mcf decreased 46.4%, from $10.08 in 2008 to $5.40 in 2009. The decrease in gas sales volume is primarily due to the normal decline in production in the Antenna Federal property in Weld County, Colorado. On an equivalent barrel (BOE) basis, sales volume decreased 2.8% from 31,090 BOE in 2008 to 30,207 BOE in 2009.

Expenses. Oil and gas production expense decreased $98,000 (17.3%) in 2009 over 2008, primarily due to routine lease operating expense declining by $114,000 (25.2%) from $453,000 in 2008 to $339,000 in 2009 as a result of decreasing vendor prices and shutting in high cost wells. Workover expense, which is more volatile than routine lease operating expense, increased $16,000 (14.2%) from $113,000 in 2008 to $129,000 in 2009. Routine lease operating expense per BOE decreased 23.0% from $14.61 in 2008 to $11.22 in 2009 while workover expense per BOE increased 17.5% from $3.63 in 2008 to $4.27 in 2009.

Production taxes, which are generally a percentage of sales revenue, decreased $162,000 (57.4%) in 2009 compared to 2008 primarily due to the decline of oil prices. Production taxes, as a percent of sales revenue decreased from 8.5% in 2008 to 8.1% in 2009. The overall lifting cost (oil and gas production expense and production taxes) per BOE decreased 28.6% from $27.28 in 2008 to $19.47 in 2009.

Depreciation, depletion and amortization expense increased $17,000 (7.7%) in 2009 compared to 2008 as a result of a decrease in our reserve values due to the decline in oil and gas prices.

General and administrative expense increased $32,000 (10.6%) in 2009 over 2008. These increases were primarily the result of increased expenditures attributable to the graduated increase in office rent and audit fees. G&A expense per BOE increased 13.8% from $9.75 in 2008 to $11.09 in 2009. As a percent of total sales revenue, G&A expense increased from 9.2% in 2008 to 22.7% in 2009.

Income Tax Expense. For the three months ended June 30, 2009, we recorded an income tax benefit of $(10,000) as compared to income tax expense of $596,000 for the three months ended June 30, 2008. Our effective income tax rate decreased from 29.97% for the three months ended June 30, 2008 to 25.62% for 2009. Our effective income tax rate was lower for 2009 primarily due to an increase in estimated deductions for statutory depletion.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

As a crude oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially and adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is to a large extent determined by factors beyond our control.

Item 4T. 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 Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosures.

For the quarter ended June 30, 2009 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 June 30, 2009 that have materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 1A. Risk Factors.

As a “smaller reporting company,” we are not required to provide this information.

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

Purchases of Equity Securities

The following table summarizes stock repurchase activity for the three months ended June 30, 2009:

	Total Number of Shares Purchased (1)		Average Price Paid Per Share	Number of Shares Purchased as Part of a Publicly Announced Plan (1)		Maximum Shares that May Yet be Purchased under the Plan (1)

April 1, 2009 – April 30, 2009	3,400	$	0.78	3,400	$	466,400
May 1, 2009 – May 31, 2009	3,600	$	0.78	3,600	$	462,800
June 1, 2009 - June 30, 2009(2)	200,000	$	0.78	200,000	$	262,800

Total	207,000	$	0.78	207,000	$	262,800

(1)

In October 2008, the Company’s Board of Directors authorized a stock buyback program for the Company to repurchase up to 500,000 shares of its common stock. The program does not have a specified expiration date, it does not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time. During the three months ended June 30, 2009, 207,000 shares were repurchased under the stock buyback program and 262,800 shares remain available for future repurchase.

(2)

Of the shares purchased during this month, 200,000 were purchased in a private arms-length transaction at the market price.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

None.

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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).

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SIGNATURES

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

BASIC EARTH SCIENCE SYSTEMS, INC.
By: /s/ Ray Singleton
Ray Singleton
President and Chief Executive Officer

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

Date: August 12, 2009