UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-KSB

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

For the Fiscal Year Ended March 31, 2008

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

Commission file number: 0-7914

BASIC EARTH SCIENCE SYSTEMS, INC.

633 17th Street, Suite 1645

Denver, Colorado 80202-3625

Telephone (303) 296-3076

Incorporated in Delaware IRS ID# 84-0592823

Securities registered under Section 12(b) of the Act: NONE

Securities registered under Section 12(g) of the Act: Common Stock, $.001 par value

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No þ

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

Check if disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, and no disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. o

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

Issuer’s revenues for its most recent fiscal year: $7,447,000

As of July 10, 2008 17,465,585 shares of the registrant’s common stock were outstanding and the aggregate market value of such common stock held by non-affiliates was approximately $23,781,000.

Basic Earth Science Systems, Inc.

Form 10-KSB

March 31, 2008

Table of Contents

	Part I	Page
Item 1	Description of Business	1
Item 2	Description of Property	7
Item 3	Legal Proceedings	9
Item 4	Submission of Matters to a Vote of Security Holders	9
	Part II
Item 5	Market for Common Equity and Related Stockholder Matters	10
Item 6	Management's Discussion and Analysis or Plan of Operation	10
Item 7	Financial Statements	18
Item 8	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	53
Item 8A	Controls and Procedures	53
Item 8B	Other Information	56
	Part III
Item 9	Directors, Executive Officers, Promoters and Control Persons and Corporate Governance; Compliance with Section 16(a) of the Exchange Act	57
Item 10	Executive Compensation	60
Item 11	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	63
Item 12	Certain Relationships, Related Transactions, and Director Independence	64
Item 13	Exhibits and Reports on Form 8-K	64
Item 14	Principal Accountant Fees and Services	65
	Signatures	66

Explanatory Note

During the preparation and review of our 2008 income tax provision, we discovered errors in calculating the GAAP cost basis of our oil and gas properties in determining deferred tax liability and the estimated deferred tax asset for percentage depletion carryforward for fiscal years ended March 31, 2007 and 2006 under SFAS 109– Accounting for Income Taxes. During this review, we also determined that it would be appropriate to correct what we considered to be immaterial differences to properly reconcile accounting for stock option compensation for purposes of determining deferred tax liability for the fiscal year ended March 31, 2007 under SFAS 109 – Accounting for Income Taxes.

In accordance with the provisions of SFAS 154 – Accounting Changes and Error Corrections, we have restated, to the earliest period practical, our previously filed financial statements. See Note 2 – Restatement of Financial Statements in Notes to Consolidated Financial Statements in Item 7 – Financial Statements of this Annual Report on Form 10-KSB, for the effect of the restatements on fiscal years 2007 and 2006, and Note 13 – Quarterly Financial Data (Unaudited) in Notes to Consolidated Financial Statements in Item 7 – Financial Statements of this Annual Report on Form 10-KSB, for the effect of the restatements on the interim condensed financial information for the first three quarters of fiscal year 2008 and all four quarters of fiscal years 2007 and 2006.  We have not amended and do not intend to amend any of our previously filed Annual Reports on Form 10-KSB or Quarterly Reports on Form 10-QSB for the periods affected by these restatements. 

Deferred income taxes is a non-cash flow item, therefore this restatement had no effect on cash or cash flow from operations.

Part I

ITEM 1

DESCRIPTION OF BUSINESS

Overview

Basic Earth Science Systems, Inc. (“Basic” or “the Company” or “we” or “our” or “us”) is an independent oil and gas exploration company focusing on the fundamentals of company growth and profitability in an effort to enhance shareholder wealth. We are engaged in the exploration, acquisition, development, operation, production and sale of crude oil and natural gas. We have an established production base that generates positive cash flow and profits. Our activities are focused in the North Dakota and Montana portions of the Williston basin, the Denver-Julesburg basin of Colorado, the southern portions of Texas, and along the onshore portions of the Gulf Coast.

Strategy

The three components of our growth strategy are:

• Cost effective implementation of internally and externally generated exploration and development drilling projects.

• Identification and acquisition of strategic producing properties; strategic and significant in that they are either synergistic to our existing production or will provide a dramatic increase to the Company’s existing production base.

• Boosting cash flows from existing oil and gas production through a combination of cost control and the exploitation of behind-pipe potential.

Our primary exploration focus is in the Montana and North Dakota portions of the Williston basin. We have been involved in the Williston basin since the early 1980’s and only in south Texas does the Company have a longer history. As such, we have significant understanding of and exposure to both geology and operations in the area. However, both the Williston basin and our south Texas waterfloods are primarily oil productive. Sensitive to the need to increase our natural gas output and balance our product base, our efforts in other areas, notably Colorado and on-shore portions of the Gulf Coast, are simply to increase our exposure to natural gas projects.

Areas of Focus

WillistonBasin.  The Williston basin continues to be our primary area of focus, both in terms of future cash flow from existing properties and future expenditures. In the coming year, we intend to increase our efforts to acquire properties in the Williston basin (especially in the northern portion of the basin) while we continue to exploit ongoing drilling prospects. From a drilling perspective, we have three major areas within the Williston basin where we expect drilling operations to commence or continue during the current fiscal year. These areas are our on-going Banks prospect in McKenzie County, North Dakota, the on-going horizontal Madison drilling efforts in the TR Madison unit in Billings County, North Dakota and our South Flat Lake prospect in Sheridan County, Montana. We caution that the following expectations may be altered by subsequent events or other, more attractive opportunities that may present themselves in the future.

1

Banks Prospect — McKenzie County, North Dakota.   In the June 2005 quarter, we acquired a 20% interest in 13,000 acres in our Banks prospect in McKenzie County, North Dakota primarily to position the Company in the developing, though unproven, extension of the Bakken horizontal play into North Dakota. Following discouraging results, we elected to pursue development of the Rival formation. In the intervening period, the success of new techniques by various companies has given new life to the horizontal Bakken play in North Dakota. As these ventures have expanded from their core discovery wells, they have neared the eastern boundary of our Banks prospect.  The success of these offset wells has dramatically enhanced the viability of the Bakken formation in our Banks Prospect.  As a result, we and our partners have been approached by several companies wishing to acquire part of our interest in exchange for cash and a carried working interest in several new horizontal wells that these companies would be required to drill.  Following the completion of “carried wells,” we would have 35% to 40% of our original working interest (or 7% to 8% working interest, proportionately reduced) in wells subsequently drilled on the acreage.   While attractive, details of such an agreement have not been acceptable and no agreement has been finalized.  Furthermore, there are no assurances that such an agreement will be finalized.  If an agreement can be reached, we expect drilling operations to commence within 30 to 60 days.

TR Madison Unit Prospect — Billings County, North Dakota.In May 2003 the North Dakota Industrial Commission created the TR Madison Unit for the purpose of enhancing the ultimate recovery from the Madison formation in the TR Field. Approximately nineteen existing wells were originally included in the Unit. By virtue of its interest in one of these wells we acquired a 1.075% working interest (0.833% net revenue interest) in the Unit. During the previous four years, six new horizontal wells have been drilled and four originally vertical wells have had horizontal laterals added. Three of these new horizontal wells were drilled in the year ended March 31, 2008.  Following the end of the fiscal year one additional well has been drilled but not yet completed.  While our interest in this effort is relatively small, this property has now become our 7th largest producer in terms of cash flow, up from 10th last year. More importantly these gains have been made with relatively low risk and low cost (relative to our cash position).

SouthFlatLake Prospect — Sheridan County, Montana. We have acquired leases on approximately 4,200 gross acres (1,900 net) in northern Sheridan County near the Flat Lake Field. Developed by a geologist on retainer by us, South Flat Lake represents the first exploration prospect we have generated in more than a decade. To defray the cost of this effort, land, legal and geologic costs were funded equally by us and our 50% partner in this venture, an unrelated, non-public company. Our partner expects to sell a portion of this prospect to others to help defray their share of the cost of drilling. As an exploratory venture, this prospect is considered high risk and no assurance of its ultimate success can be offered. Presently, the Montana Oil & Gas Commission has granted a drilling permit and the surface location has been prepared for drilling operations.  We expect to commence drilling operations before the end of the calendar year.

Other Areas

The following areas are primarily gas productive and provide us exposure to natural gas projects.

Denver-JulesbergBasin — Weld County, Colorado.  We have previously disclosed our project to drill sixteen down-spaced wells on its Antenna federal property in Weld County, Colorado.  At March 31, 2008 all sixteen new wells had been drilled.  Of the now 32 total wells, eight of the new wells and eight of the original sixteen old wells were producing.  The eight remaining new wells and eight remaining original wells were not producing in that they were awaiting completion of newly designed and refurbished production facilities.  We were impacted in our fourth quarter and a portion of its third quarter because all of the original wells were shut-in to allow these new production facilities to be built.  We expect to have a 2% to 52.5% revenue interest in Codell/Niobrara production and a 13.125% to 52.5% revenue interest in J-Sand production (depending on actual well location).  However, initially, all new wells will produce from the Codell/Niobrara formation alone.  We expect to spend a total of $2.5 million for our share of the cost of drilling and completing these wells.  Kerr-McGee Oil & Gas Onshore, LP will be the Operator of the project.

2

Onshore GulfCoast. During the past few years, we participated in five wells in this area; primarily pursuing “3-D Bright Spots.” We intend to look at and evaluate additional ventures in this area for possible future participation. However, our future involvement in this area will depend on the quality of prospects we review, the operational record of designated operators and the risk associated with specific ventures.

Christmas Meadows Prospect — Summit County, Utah. In fiscal 2007, we participated with Double Eagle Petroleum Company (“Double Eagle”) in one of the more exciting, true wildcat projects in the Rocky Mountain region, Christmas Meadows. Christmas Meadows is a structural dome in the southwest corner of the prolific Green River Basin, in Summit County, Utah. The dome is overlain by the Wyoming Overthrust Belt and the North Flank Thrust of the Uinta Mountains. During the first quarter of 2007, drilling at the Table Top Unit #1 well reached the originally planned depth of 15,760 feet. The drill cuttings did not reveal reservoir rocks (due to either insufficient hydraulics to bring those cuttings to surface undamaged and intact or because they did not exist).  Operations were suspended to assess alternative approaches to completing the project. The wellbore was sealed at 11,000 feet (the base of the intermediate casing) in order to prevent any abnormal pressure from migrating to surface.  The Table Top Unit, as originally formed, was dissolved, and, having met the governmental permitting obligation for the Unit test, the time-frame has been extended for drilling the newly formed Main Fork Unit until at least April 2009. We are in the process of evaluating potential alternatives, including drilling or farming out the drilling of the Table Top Unit #1 to drill deeper to the Nugget Sandstone at approximately 18,000 feet. Double Eagle has disclosed that it is in discussions with several larger or major companies to take over this venture and deepen this wellbore down to the deeper Nugget formation. While Double Eagle’s personnel have expressed excitement about this situation, given the recent premature and unexpected departure of Double Eagle’s long-time management, the possibility exists that little, or no, progress could occur.  If this does occur, this leasehold may expire of its own terms and we, Double Eagle, and our partners would be required to plug this well and reclaim the access road. We have a 1.5% interest in all future operations in this wellbore and in any future operations on the Christmas Meadows prospect.

Contemplated Activities

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

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

Segment Information and Major Customers

Industry segment. We are engaged only in the upstream segment of the oil and gas industry, which comprises exploration, production, operations and development. We have no gathering, transportation, refining or marketing functions.

Markets. Our oil and natural gas is sold to various purchasers in the geographic area of its properties. We are a small company and, as such, have no impact on the market for our goods and little control over the price received. The market for, and the value of, oil and natural gas are dependent upon a number of factors including other sources of production, competitive fuels, and proximity and capacity of pipelines or other means of transportation, all of which are beyond our control. For more information see Note 1 - Major Customers and Concentration of Credit Risk in the Notes to Consolidated Financial Statements.

3

Competition

The oil and gas industry is a highly competitive and speculative business. We encounter strong competition from major and independent oil companies in all phases of our operations. In this arena, we must compete with many companies having financial resources and technical staffs significantly larger than our own. Furthermore, having pursued an acquisition strategy for over a decade, we did not develop an in-house geologic or geophysical infrastructure, as have many of our competitors. Rather than incur the time and expense to develop in-house capability, we chose to enter joint ventures with other companies to accelerate our efforts.

With respect to acquisitions, competition is intense for the purchase of large producing properties. Because of the limited capital resources available to us, we have historically focused on smaller and/or marginal properties with behind-pipe potential in our acquisition efforts.

Regulations

General. Our operations are affected in varying degrees by federal, state, regional and local laws and regulations, including, but not limited to, laws governing well spacing, air emissions, water discharges, reporting requirements, endangered species, marketing, prices, taxes, allowable rates of production and the plugging and abandonment of wells and the subsequent rehabilitation of the wellsite locations. We are further affected by changes in such laws and by constantly changing administrative regulations. To the best of our knowledge, we are in compliance with all such regulations and are not aware of any claims that could have a material impact upon our financial condition, results of operations, or cash flows.

Environmental matters. We are subject to various federal, state, regional and local laws and regulations related to the discharge of materials into, and the protection of, the environment. These laws and regulations, among other things, may impose liability on the owner or the lessee for the cost of pollution cleanup resulting from operations, subject the owner or lessee to liability for pollution damages, require the suspension or cessation of operations in affected areas and impose restrictions on injection into subsurface formations in order to prevent the contamination of ground water. All but three of the disposal wells that we utilize are owned and operated by third parties whose disposal practices are outside of our control. With respect to the three disposal wells that we own and operates, we currently use these facilities only for the disposal of produced water from other Company-operated properties. Although environmental requirements do have a substantial impact upon the energy industry, these requirements do not appear to affect us any differently than other companies in this industry who operate in a given geographic area. We are not aware of any environmental claims which could have a material impact upon our financial condition, results of operations, or cash flows.

Such regulations have increased the resources required and costs associated with planning, designing, drilling, operating and both installing and abandoning oil and natural gas wells and facilities. As yet, we have not had to hire any new employees to comply with these regulations. We will continue to make expenditures in our efforts to comply with these requirements, which are unavoidable business costs in the oil and gas industry.

Although we are not fully insured against all environmental and other risks, we maintain insurance coverage that we believe is customary in the industry.

4

Risk Factors

Volatility of oil and gas prices. Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties are highly dependent upon prevailing market prices for oil and gas. Historically, the markets for oil and gas have been volatile and in certain periods have been depressed by excess domestic and imported supplies. Such volatility can be expected to reoccur in the future. Various factors beyond our control will affect prices of oil and gas, including worldwide and domestic supplies of oil and gas, the ability of the members of the Organization of Petroleum Exporting Countries to agree to maintain oil price and production controls, political instability or armed conflict in oil and gas producing regions, the price and level of foreign imports, the level of consumer demand, the price, availability and acceptance of alternative fuels and weather conditions. In addition to market factors, actions of state and local agencies and the United States and foreign governments affect oil and gas prices. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and gas. Any substantial or extended decline in the price of oil would have a material adverse effect on our financial condition and results of operations. Such decline would reduce our cash flow and borrowing capacity and both the value and the amount of our existing oil and gas reserves.

We believe that substantially all of our domestic oil produced can be readily sold at prevailing market prices. For March 2008 the price differential ranged from $2.50 to $14.00 below the U.S. crude spot price. There are several factors leading to this continuing price differential. The Williston basin has seen an increase in production due to a surge in new Bakken horizontal wells which has led to pipeline capacity shortages in the area. The situation is further compounded by limited refinery capacity and reduced refinery intake during times of equipment repair and facility upgrades.

Substantially all of our gas production is sold at prevailing wellhead gas prices, subject to additional charges customary to an area. We do not own or operate any gas gathering or processing plant facilities nor do we possess sufficient volume on any pipeline to market our product to end users.

Uncertainty of reserve information and future net revenue estimates. There are numerous uncertainties inherent in estimating quantities of proved and unproved oil and gas reserves and their values, including many factors beyond our control. The reserve information set forth in this Form 10-KSB (see Note 12 to the Consolidated Financial Statements) represents estimates only. Reserve estimates are imprecise and may materially change as additional information becomes available.

Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating the future recovery of underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any estimate is a function of the quality of available data, engineering, and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as future operating costs, severance and excise taxes, development costs, workover costs, remedial costs and the assumed effects of regulations by governmental agencies, all of which may in fact vary considerably from actual results. Other variables, especially oil and gas prices, are fixed at the prices existing on March 31, the last day of the fiscal year, whether such prices are reasonable; and which may vary considerably from actual prices received over any given period of time in the past or in the future. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any property or any group of properties, classifications of such reserves based upon risk of recovery, and estimates of the expected future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

5

Reserves, as calculated according to SEC regulations and referred to in this Form 10-KSB, should not be construed as the current market value of the estimated oil and gas attributable to our properties. The timing of actual future net cash flows from proved reserves, and thus their actual present value, will be affected by the timing of both the production and incidence of expenses in connection with both extraction costs and development costs. In addition, the 10% discount factor, which is required to be used for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect at the time of calculation.

Reserve replacement. Our future success is highly dependent on our ability to find, develop and/or acquire additional oil and gas reserves that are economically recoverable. Without continued successful exploitation, exploration or acquisition projects, our current oil and gas reserves will decline as they are depleted by production.

Operating hazards. The oil and gas business involves certain operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could result in substantial losses. In addition, we may be liable for environmental damage caused by previous owners of properties purchased or leased by us. As a result, substantial liabilities to third parties or governmental agencies may be incurred, the payment of which could reduce or eliminate the funds available for acquisitions, development, and exploration, or result in losses to the Company. Although we are not fully insured against all environmental and other risks, we maintain insurance coverage which we believe is customary in the industry.

Other

The oil and gas business is not generally seasonal in nature, although unusual weather extremes for extended periods may increase or decrease demand for oil and natural gas products temporarily.  Additionally, catastrophic events, such as hurricanes or other supply disruptions, may also temporarily increase the demand for oil and gas supplies. Such events and their impacts on oil and gas commodity prices may cause fluctuations in quarterly or even annual revenues and earnings. Also, because of the location of many of our properties in Montana and North Dakota, severe weather conditions, especially in the winter months, could have a material adverse effect on our operations and cash flow.

At March 31, 2008 we had eight full-time and two part-time employees: four full time and two part-time at its main office in Denver and four field laborers at a subsidiary’s field office in Bruni, Texas, located forty-five miles east, southeast of Laredo, Texas. In addition to eleven contract field workers on retainer, at times we hire up to five contract technical/professional personnel in our main office on a project-by-project basis.

Forward-Looking Statements

This Form 10-KSB 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-KSB including, without limitation, the statements under Item 1. “Description of Business” and Item 6. “Management’s Discussion and Analysis and Plan of Operation” and the statements located elsewhere herein regarding our financial position and liquidity, the amount of and our ability to make debt service payments should we utilize some or all of our available borrowing capacity, our strategies, either existing or anticipated, 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-KSB in conjunction with the forward-looking statements included in this Form 10-KSB.

6

Our intentions and expectations described in this Form 10-KSB with respect to possible exploration and development activities concerning properties in which we hold interests may be deemed to be forward-looking statements. These statements are made based on our current assessment of the exploratory and development merits of the particular property in light of the geological information available at the time and based on our relative interest in the property and our estimate of our share of the exploration and development cost. Subsequently obtained information concerning the merits of any property, as well as changes in estimated exploration and development costs and ownership interest, may result in revisions to our expectations and intentions and, thus, we may alter our plans regarding these exploration and development activities. Furthermore, circumstances beyond our control may cause such prospects to be eliminated from further consideration as exploration and/or development prospects.

ITEM 2

DESCRIPTION OF PROPERTY

Producing Properties: Location and Impact

At March 31, 2008, we owned a working interest in 90 producing oil wells and 14 producing gas wells. We currently operate 54 of these wells in five states: North Dakota, Montana, Colorado, Texas and Wyoming. These operated wells contributed approximately 57% of both our total liquid hydrocarbon sales and total natural gas sales in fiscal 2008. A significant portion of our production is encumbered and used to secure bank debt.

Producing Property

	Gross Wells				Net Wells
	Oil		Gas		Oil		Gas
Colorado		—		12		—		5.40
Louisiana		1		1		0.01		0.10
Montana		19		—		9.51		—
North Dakota		46		—		9.28		—
Texas		23		1		20.66		0.11
Wyoming		1		—		0.47		—
Total		90		14		39.9		5.6

Production

Specific production data relative to our oil and gas producing properties can be found in the Selected Financial Information table in Item 6 “Management’s Discussion and Analysis and Plan of Operation.”

Reserves

At March 31, 2008, our estimated proved developed oil and gas reserves in barrels of oil equivalent (BOE) was 1,229,000, a 3.7% increase over the prior year’s estimated proved developed oil and gas reserves of 1,185,000 BOE. However, due to increases in oil and gas prices, our standardized measure of discounted future net cash flows was $24,960,000, a 70.7% increase from the prior year’s standardized measure of discounted future net cash flows of $14,624,000. Further discussion of our estimated oil and gas reserves can be found in Note 12 to the Consolidated Financial Statements.

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Geographically, our reserves are located in three primary areas: the Williston basin in North Dakota and Montana, the Denver-Julesburg (D-J) basin in Colorado and on-shore south Texas. The following table summarizes the estimated proved developed oil and gas reserves divided between operated and non-operated properties for these three areas as of March 31, 2008:

	Net Oil		Net Gas
	(Bbls)		(Mcf)		BOE		%
Williston Basin
Operated		323,000		40,000		329,667		26.2
Non-Operated		323,000		203,000		356,833		28.3
		646,000		243,000		686,500		54.5
South Texas/Onshore Gulf Coast
Operated		394,000		5,000		394,833		31.3
Non-Operated		—		188,000		31,359		2.5
		394,000		193,000		426,192		33.8
D-J Basin
Operated		11,000		537,000		100,500		8.0
Non-Operated		18,000		146,000		42,333		3.3
		29,000		683,000		142,833		11.3
Other Areas
Operated		5,000		—		5,000		0.4
Non-Operated		—		—		—		—
		5,000		—		5,000		0.4
Total		1,074,000		1,119,000		1,260,526		100

Leasehold Acreage

We lease the rights to explore for and produce oil and gas from mineral owners. Leases (quantified in acres) expire after their primary term unless oil or gas production is established. Prior to establishing production, leases are considered undeveloped. After production is established, leases are considered developed or “held-by-production.” Our acreage is comprised of developed and undeveloped acreage. As we have shifted to a growth strategy that is more focused on adding reserves through exploration and development drilling, we have begun to acquire various developed and undeveloped leasehold interests. To-date, our largest acreage acquisition has been a 20% interest in 13,000 gross acres in the Banks prospect in McKenzie County, North Dakota.

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	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Colorado		640		384		—		—
Louisiana		687		51		—		—
Montana		6,330		3,126		5,662		3,127
North Dakota		13,733		2,289		26,506		4,623
Texas		3,080		2,486		—		—
Utah		—		—		35,945		719
Wyoming		1,555		329		40		1
Total		26,025		8,665		68,153		8,470

Field Service Equipment

At March 31, 2008, one of our subsidiaries, Basic Petroleum Services, Inc. located in Bruni, Texas, owned a trailer house/field office, a shallow pulling rig, a large winch truck, a skid-mounted cementing unit, four pickup trucks and various ancillary service vehicles. None of the vehicles are encumbered.

Office Lease

We currently lease approximately 4,000 square feet of office space in downtown Denver, Colorado from an independent third party for approximately $5,500 per month escalating at a rate of approximately $170 at the end of each year. The lease term is for a five-year period ending April 30, 2013. For additional information see Note 7 to the Consolidated Financial Statements.

ITEM 3

LEGAL PROCEEDINGS

None.

ITEM 4

SUBMISSION OF MATTERS TO A VOTE

OF SECURITY HOLDERS

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

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

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

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Part II

ITEM 5

MARKET FOR COMMON EQUITY

AND RELATED STOCKHOLDER MATTERS

Our common stock is traded in the over-the-counter market. The following table sets forth the range of high and low closing bid prices for each quarter of the last two fiscal years.

	High		Low
Year Ended March 31, 2007
First Quarter	$	2.85	$	2.00
Second Quarter		2.29		1.66
Third Quarter		2.22		1.77
Fourth Quarter		1.90		1.52
Year Ended March 31, 2008
First Quarter	$	1.64	$	1.30
Second Quarter		1.45		0.95
Third Quarter		1.23		1.01
Fourth Quarter		1.12		0.89

The closing bid price on July 10, 2008 was $1.95. Transactions on the over-the-counter market reflect inter-dealer quotations, without adjustments for retail mark-ups, mark-downs or commissions to the broker-dealer and may not necessarily represent actual transactions.

As of July 10, 2008, we had approximately 1,868 shareholders of record. We have never paid a cash dividend on its common stock. Any future dividend on common stock will be at the discretion of the Board of Directors and will be dependent upon the Company’s earnings, financial condition, and other factors. Our Board of Directors presently has no plans to pay any dividends in the foreseeable future.

ITEM 6

MANAGEMENT’S DISCUSSION AND ANALYSIS

AND PLAN OF OPERATION

Liquidity Outlook

Our primary source of funding is the net cash flow from the sale of its 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 then sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. Assuming oil prices do not decline significantly from current levels, we believe the cash generated from operations will provide sufficient working capital for us to meet our existing and normal recurring obligations as they become due. In addition, as mentioned in the “Debt” section below, we have an available borrowing capacity of $4,000,000 as of July 11, 2008.

Capital Structure and Liquidity

Overview. We recognize the importance of developing our capital resource base in order to pursue our objectives. However, subsequent to our last public offering in 1980, debt financing has been the sole source of external funding.  In addition to our routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, we require capital to fund our exploratory and development drilling efforts, and the acquisition of additional properties as well as any development and enhancement of these acquired properties.

10

We have received numerous inquiries regarding the possibility of funding our efforts through equity contributions or debt instruments. Given strong cash flows, and the relatively modest nature of our current drilling projects, we have thus far declined these overtures. Our primary concern in this area is the dilution of our existing shareholders. However, going forward, given that one of the key components of our growth strategy is to expand our oil and gas reserve base through exploration and development drilling, if we were presented with a significant opportunity and available cash and bank debt financing were insufficient, it is possible we would consider alternative forms of additional financing.

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, while for the year ended March 31, 2007 we utilized our credit facility to fund portions of our drilling program and incurred interest charges of $6,000. Our effective annual interest rate was 8.50% at March 31, 2008 and 2007. On July 11, 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. See Note 6 to the Consolidated Financial Statements for a more detailed discussion of our bank credit facility.

Hedging. During 2008 and 2007, we did not participate in any hedging activities, nor did we have any open futures or option contracts.  Additional information concerning our hedging activities appears in Note 1 to the Consolidated Financial Statements.

Working Capital. At March 31, 2008, we had a working capital surplus of $3,176,000 (a current ratio of 2.11:1) compared to a working capital surplus at March 31, 2007 of $2,057,000 (a current ratio of 2.03:1). The primary difference from 2007 to 2008 was a substantial increase in cash and cash equivalents resulting from the combined effect of improved cash flow from operations with a drop in the amount of funds used in investing activities.

Cash Flow. As mentioned above, our primary source of funding is the cash flow from its operations. Cash provided by operating activities decreased 15.7% from $4,283,000 in 2007 to $3,609,000 in 2008. Net cash used in investing activities decreased 59.3% from $1,413,000 in 2007 to $575,000 in 2008, which relates primarily to our drilling activities during the year.

We have not borrowed on our line of credit since June 2006. Cash used in financing activities was $425,000 in 2007 principally for repayment of debt, while cash provided by financing activities was $14,000 in 2008, from the proceeds of stock option exercise.

Capital Expenditures. During 2008 our capital expenditures were primarily focused in the DJ Basin of Colorado. Total capital expenditures during 2008 for oil and gas property and equipment and various leasehold interests were $2,700,000. Seventy-nine percent of these costs are from the Antenna Federal property in the DJ Basin of Colorado for the drilling and/or completion of the first eleven wells.  These projects were primarily funded with internally generated cash flow from operations. See also the Areas of Focus and Company Developments sections of Part 1 of this report for further discussion related to our exploration and development activities.

11

We are continually evaluating exploration, development and acquisition opportunities in an effort to grow our oil and gas reserves. At present cash flow levels and 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.

Divestitures/Abandonments. We plugged four wells during 2008 and incurred some additional costs pertaining to the abandonment of wells that were plugged in prior periods.

Impact of Inflation. Inflation has not had a material impact on the Company in recent years because of the relatively low rates of inflation in the United States. While the US dollar has weakened compared to foreign currencies during the year, the prices of oil and gas have hit all time highs, and we deal primarily in US dollars.

Other Commitments. We have no obligations to purchase additional, or sell any existing, oil and gas property. We also do not have any other commitments beyond our office lease and software maintenance contracts (see Note 7 to the Consolidated Financial Statements).

Restatement and Impact on Financial Statements

During the preparation and review of our 2008 income tax provision, we discovered errors in calculating the GAAP cost basis of our oil and gas properties in determining deferred tax liability and the estimated deferred tax asset for depletion carryforward for fiscal years ended March 31, 2007 and 2006 under SFAS 109- Accounting for Income Taxes. During this review, we also determined that it would be appropriate to correct what we considered to be immaterial differences to properly reconcile accounting for stock option compensation for purposes of determining deferred tax liability for the fiscal year ended March 31, 2007 under SFAS 109 – Accounting for Income Taxes. The foregoing impacted our previously filed financial statements for the fiscal years 2007 and 2006 and our previously filed interim financial statements for those years related to our tax liabilities and our income tax provision.

In accordance with the provisions of SFAS 154 – Accounting Changes and Error Corrections, we have restated, to the earliest period practical, our previously filed financial statements. See Note 2 – Restatement of Financial Statements in Notes to Consolidated Financial Statements in Item 7 – Financial Statements of this Annual Report on Form 10-KSB, for the effect of the restatements on fiscal years 2007 and 2006.

The following table details the net income effect of these corrections for fiscal years 2006 and 2007:

Fiscal Year	Net Income as Previously Reported		Increase in Provision for Deferred Income Taxes			Net Income as Restated
2007	$	2,500,000	$	(445,000	)	$	2,055,000
2006	$	2,815,000	$	(482,000	)	$	2,333,000

See Note 2 – Restatement of Financial Statements in Notes to Consolidated Financial Statements in Item 7 – Financial Statements in this Annual Report on Form 10-KSB, for further discussion on the effect of these corrections for fiscal years 2007 and 2006 to the previously reported amounts.

12

Results of Operations

Fiscal 2008 Compared with Fiscal 2007

Overview. Net income for the year ended March 31, 2008 was $1,763,000 compared to net income of $2,055,000 as restated for the year ended March 31, 2007, a 14.2% decrease. Earnings for 2008 were greatly impacted by the current year income tax expense and the provision for deferred income taxes following utilization of the remaining tax net operating loss carry-forward in 2006, as well as increased general and administrative and production expenses.

Revenues. Oil and gas sales revenue increased $286,000 (3.9%) in 2008 over 2007 as a result of higher average oil prices. Oil sales revenue alone increased $634,000 (9.4%). Gas sales revenue alone decreased $348,000 (34.3%) in 2008 from 2007.

Volumes and Prices. Decline in production on the two relatively new Halverson wells, Richland County, Montana along with salt water disposal issues on the West Cole North Unit, Webb County, Texas contributed to a decrease in oil sales volumes of 14% from 104,000 barrels in 2007 to 89,000 barrels in 2008 while the average price per barrel increased 29% from $58.70 in 2007 to $75.47 in 2008. Gas sales volume decreased 30% from 155.8 million cubic feet (MMcf) in 2007 to 108.6 MMcf in 2008 while the average price per Mcf dropped 6%, from $6.51 in 2007 to $6.13 in 2008. The production decrease in gas was primarily due to the Antenna Federal wells being temporarily shut in for the rebuilding of tank batteries.  On an equivalent barrel (BOE) basis, sales decreased 17% from 130,000 BOE in 2007 to 108,000 BOE in 2008.

Expenses. Oil and gas production expense increased $150,000 (7.8%) 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.

Routine lease operating expense increased $42,000 (3%) from $1,560,000 in 2007 to $1,602,000 in 2008, which is relatively consistent. Workover expense increased $108,000 (29%) from $375,000 in 2007 to $483,000 in 2008 primarily as a result of additional workover expenses on various wells in 2008. On an equivalent barrel basis, routine lease operating expense increased 24% from $11.99 per BOE in 2007 to $14.84 in 2008 while workover expense increased 70% from $2.88 in 2007 to $4.89 per BOE in 2008.

Primarily as a result of the increase in oil and gas sales revenue, production taxes, which are a function of sales revenue, increased $134,000 (28%) in 2008 over 2007. Production taxes as a percent of oil and gas sales revenue actually increased from 6.8% in 2007 to 8.3% in 2008.

The overall lifting cost (oil and gas production expense plus production taxes) per BOE was $24.86 in 2008 compared to $18.61 in 2007. We caution that this cost per equivalent barrel is not indicative of all wells, and that certain high cost wells would be shut in should oil prices begin to drop below certain levels.

Depreciation, depletion and amortization expense increased $45,000 (7%) in 2008 over 2007, which is due to new wells in our Antenna Federal property. Depreciation, depletion, and amortization expense per BOE increased from $4.85 in 2007 to $6.34 in 2008.

Accretion of asset retirement obligation increased $6,000 (5%) in 2008 over 2007. This increase is a result of additional estimated future plugging and abandonment costs. Additional information concerning SFAS No. 143 and related activity during 2008 can be found in Note 3 to the Consolidated Financial Statements.

13

General and administrative (G&A) expense increased $170,000 (31%) in 2008 over 2007. This increase was primarily due to D&O insurance, board of director compensation, consulting fees in connection with Sarbanes-Oxley implementation, and increased employee compensation consistent with the Company’s growth.  The percentage of G&A expense that we were able to charge out to operated properties was 22% in 2008 compared to 27% in 2007. G&A expense per BOE increased 41% from $4.20 in 2007 to $5.94 in 2008. G&A expense as a percentage of total sales revenue also increased from 7.7% in 2007 to 10% in 2008.

Other Income/Expense. Due to significantly higher cash balances throughout the year, Interest and other income increased from $50,000 in 2007 to $152,000 in 2008. Also in 2007, we recorded as other income a refund, plus accrued interest, totaling $79,000 from the Department of Energy for overpayments related to fuel purchases made from 1973 through 1980 by a wholly-owned subsidiary of the Company that has been inactive since 1980.  Interest and other expenses, increased from $7,000 in 2007 to $28,000 in 2008.

Income Taxes. In 2008, we recorded income tax expense of $1,525,000 comprised of a current year income tax provision of $179,000, and a deferred income tax provision of $1,346,000. This compares to a 2007 income tax expense of $326,000, as restated. At March 31, 2007 we had a net deferred tax liability of $1,026,000, as restated. However, with a combination of our net income from operations over the past few years and the expensing of intangible drilling and completion costs for tax purposes during these years, our net deferred tax asset has been utilized and we are now in a deferred tax liability position. Going forward, under a scenario of sustained net income from operations, we anticipate recording an income tax expense each year that should approximate 39%. The effective tax rate for 2008 was 46% of pre-tax income, which differs from the expected future rate primarily because of the change in fiscal 2008 of the percentage depletion carryforward as restated from fiscal 2007.

Fiscal 2007 Compared with Fiscal 2006

Overview. Net income for the year ended March 31, 2007 was $2,055,000 (as restated) compared to net income of $2,333,000 (as restated) for the year ended March 31, 2006, an 12% decrease. Earnings for 2007 were greatly impacted by the current year income tax expense and the provision for deferred income taxes following utilization of the remaining tax net operating loss carry-forward in 2006.

Revenues. Oil and gas sales revenue increased $534,000 (8%) in 2007 over 2006 as a result of both an increase in volume sales and higher average oil prices. Oil sales revenue alone increased $585,000 (11%). An increase in sales volume in 2007 contributed $235,000 while higher average oil prices in 2007 added $350,000. Gas sales revenue alone decreased $51,000 (5%) in 2007 from 2006. A positive variance of $114,000 from higher volume sales was more than offset by a $165,000 negative variance attributable to a lower average price for natural gas.

Volumes and Prices. As a result of new production from the Halvorsen 21X-36 and two wells in our Banks prospect, oil sales volume increased 4% from 99,900 barrels in 2006 to 104,200 barrels in 2007 while the average price per barrel rose 6% from $55.35 in 2006 to $58.70 in 2007. Primarily due to new production from our Louisiana gas well, gas sales volume increased 11% from 140.8 million cubic feet in (MMcf) 2006 to 155.8 MMcf in 2007 while the average price per Mcf dropped 14%, from $7.56 in 2006 to $6.51 in 2007. On an equivalent barrel (BOE) basis, sales increased 5% from 123,400 BOE in 2006 to 130,100 BOE in 2007.

Expenses. Oil and gas production expense decreased $169,000 (8%) in 2007 from 2006. Oil and gas production expense is comprised of two components: routine lease operating expenses and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal and minor surface equipment repairs. Workovers, on the other hand, which primarily include downhole repairs, are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their cost can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas production expense from period to period.

14

Routine lease operating expense increased $218,000 (16%) from $1,342,000 in 2006 to $1,560,000 in 2007 mainly because of new wells placed on production in 2007. Workover expense dropped $387,000 (51%) from $762,000 in 2006 to $375,000 in 2007 primarily as a result of unusually high workover expenses on three properties in 2006. On an equivalent barrel basis, routine lease operating expense increased 10% from $10.88 per BOE in 2006 to $11.99 in 2007 while workover expense dropped 53% from $6.18 in 2006 to $2.88 per BOE in 2007.

Primarily as a result of the increase in oil and gas sales revenue, production taxes, which are a function of sales revenue, increased $27,000 (6%) in 2007 over 2006. Production taxes as a percent of oil and gas sales revenue actually dropped slightly from 7.0% in 2006 to 6.8% in 2007.

The overall lifting cost (oil and gas production expense plus production taxes) per BOE was $18.61 in 2007 compared to $20.78 in 2006. Basic cautions that this cost per equivalent barrel is not indicative of all wells, and that certain high cost wells would be shut in should oil prices begin to drop below certain levels.

Depreciation, depletion and impairment expense increased $90,000 (16%) in 2007 over 2006. Included in the 2006 expense is an $85,000 ceiling limitation impairment charge applicable to our Canadian operations. With respect to U.S. operations only, depreciation and depletion expense increased $175,000 (38%) in 2007 over 2006 due to extensive drilling activity at the end of 2006 and the resulting inclusion of new properties in our estimated oil and gas reserves and full cost pool depletable base in 2007. For U.S. operations only, depreciation and depletion expense per BOE increased from $3.70 in 2006 to $4.85 in 2007.

Accretion of asset retirement obligation increased $34,000 (46%) in 2007 over 2006. This increase is a result of revisions to previous estimates of future plugging and abandonment costs. Additional information concerning SFAS No. 143 and related activity during 2007 can be found in Note 2 to the Consolidated Financial Statements.

General and administrative (G&A) expense increased $22,000 (4%) in 2007 over 2006. Increases in SEC reporting, audit related costs, and consulting fees, and a decrease in the amount of G&A expenses that we could charge out to operated properties, all were only partially offset by a decrease in employee benefits. The percentage of gross G&A expense that we were able to charge out was 27% in 2007 compared to 30% in 2006. G&A expense per BOE decreased 1% from $4.24 in 2006 to $4.20 in 2007. G&A expense as a percentage of total sales revenue also dropped slightly from 7.9% in 2006 to 7.7% in 2007.

Other Income/Expense. Due to significantly higher cash balances throughout the year, interest and other income, which consists almost entirely of interest income, increased from $23,000 in 2006 to $50,000 in 2007. Interest and other expenses, consisting primarily of interest from short-term debt financing, decreased from $11,000 in 2006 to $7,000 in 2007. Also in 2007, we recorded as other income a refund, plus accrued interest, totaling $79,000 from the Department of Energy for overpayments related to fuel purchases made from 1973 through 1980 by a wholly-owned subsidiary of the Company that has been inactive since 1980.

Income Taxes. In 2007 we recorded income tax expense of $1,352,000 as restated, comprised of a current year income tax provision of $326,000 and a deferred income tax provision of $1,026,000, as restated. This compares to a 2006 income tax expense of $495,000 as restated, comprised of a current year income tax provision of $13,000 and a deferred income tax provision of $482,000, as restated. With a combination of our net income from operations over the past few years and the expensing of intangible drilling and completion costs for tax purposes during these years, our net deferred tax asset has been utilized and we are now in a deferred tax liability position. Going forward, under a scenario of sustained net income from operations, we anticipate recording an income tax expense each year that should approximate 38%. The effective tax rate for 2007 was 27% of pre-tax income, which differs from the expected future tax rate primarily because of the utilization during 2007 of our remaining net deferred tax asset carried forward from 2006, which had previously been fully offset by a valuation allowance due to the uncertainty as to its utilization.

15

Selected Financial Information

The following table shows selected financial information and averages for each of the three prior years in the period ended March 31.

		2008		2007		2006
Production:
Oil (barrels)		89,400		104,200		99,900
Gas (Mcf)		108,600		155,800		140,800
Revenue: (in thousands)
Oil	$	6,748	$	6,115	$	5,530
Gas		667		1,014		1,065
Total		7,415		7,129		6,595
Less: Total production expense (in thousands)1		2,706		2,422		2,564
Gross profit (in thousands)	$	4,709	$	4,707	$	4,031
Depletion expense (in thousands)4	$	673	$	631	$	456
General and administrative expense (in thousands)	$	716	$	546	$	524
Average sales price2
Oil (per barrel)	$	75.47	$	58.70	$	55.35
Gas (per Mcf)		6.13		6.51		7.56
Average production expense1,2,3		19.27		18.61		20.78
Average gross profit2,3		43.96		36.17		32.66
Average depletion expense2,3,4		5.59		4.85		3.70
Average general and administrative expense2,3		5.94		4.20		4.24

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

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the 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. We understand the following accounting policies and estimates are necessary in the preparation of our consolidated financial statements: the carrying value of our oil and gas property, the accounting for oil and gas reserves, the estimate of our asset retirement obligations and the estimate of our income tax assets and liabilities.

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

Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs 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-three percent of our reported oil and gas reserves at March 31, 2008 are based on estimates prepared by an independent petroleum engineering firm. The remaining seven percent of our oil and gas reserves were prepared in-house. See also Note 12 to the Consolidated Financial Statements.

Asset Retirement Obligations. We have significant obligations related to the plugging and abandonment of our oil and gas wells, the removal of equipment and facilities, and returning the land to its original condition. SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that we estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in its 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 management 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. See also Note 3 to the Consolidated Financial Statements.

Off Balance Sheet Transactions, Arrangements or Obligations

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

Recent Accounting Pronouncements

There have been several recent accounting pronouncements, but none are expected to have a material effect on our financial position, results of operations, or cash flows. For more information, see Note 1 - Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements.

17

Basic Earth Science Systems, Inc.

Table of Contents

Consolidated Financial Statements

and Accompanying Notes

March 31, 2008, 2007, and 2006

	Page
Report of Independent Registered Public Accounting Firm – Hein & Associates LLP		19
Consolidated Balance Sheets		20-21
Consolidated Statements of Operations		22
Consolidated Statements of Shareholders’ Equity		23
Consolidated Statements of Cash Flows		24
Notes to Consolidated Financial Statements		25-53

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ITEM 7

FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Basic Earth Science Systems, Inc.

Denver, Colorado

We have audited the consolidated balance sheets of Basic Earth Science Systems, Inc. and subsidiaries (the “Company”) as of March 31, 2008, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the years then ended.  These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provided a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Basic Earth Science Systems, Inc. and subsidiaries as of March 31, 2008, 2007 and 2006, and the results of their operations and their cash flows for each of the years then ended, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, the Company has restated its 2007 and 2006 consolidated financial statements.

We were not engaged to examine management’s assertion about the effectiveness of Basic Earth Science Systems, Inc.’s internal control over financial reporting as of March 31, 2008 included in the accompanying management’s annual report on internal control over financial reporting and, accordingly, we do not express an opinion thereon.

HEIN & ASSOCIATES LLP

Denver, Colorado

July 11, 2008

19

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31,
	2008			2007			2006
				As restated			As restated
Assets
Current assets:
Cash and cash equivalents	$	5,571,000		$	2,523,000		$	78,000
Accounts receivable:
Oil and gas sales		1,110,000			825,000			913,000
Joint interest and other receivables, net of $50,000 and $70,000 in allowance		236,000			436,000			402,000
Other current assets		280,000			262,000			297,000
Total current assets		7,197,000			4,046,000			1,690,000
Oil and gas property, full cost method:
Proved property		29,050,000			27,686,000			24,257,257
Unproved property		2,515,000			1,199,000			2,880,743
Accumulated depreciation and depletion		(18,515,000	)		(17,842,000	)		(17,250,000	)
Net oil and gas property		13,050,000			11,043,000			9,888,000
Other non-current assets, net		443,000			363,000			272,000
Total non-current assets		13,493,000			11,406,000			10,160,000
Total assets	$	20,690,000		$	15,452,000		$	11,850,000

See accompanying notes to consolidated financial statements.

20

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31,
	2008			2007			2006
				As restated			As restated
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	1,443,000		$	744,000		$	389,000
Accrued liabilities		2,586,000			1,245,000			1,084,000
Total current liabilities		4,029,000			1,989,000			1,473,000
Long-term liabilities:
Long term debt		—			—			445,000
Deferred tax liability		2,800,000			1,489,000			482,000
Asset retirement obligation		1,877,000			1,802,000			1,372,000
Total long-term liabilities		4,677,000			3,291,000			2,299,000
Commitments and contingencies
Shareholders’ Equity:
Preferred stock, $.001 par value, 3,000,000 authorized, and none issued or outstanding		―			―			―
Common stock, $.001 par value, 32,000,000 shares authorized, and 17,465,585 and 17,125,585 shares issued and outstanding, respectively		17,000			17,000			17,000
Additional paid-in capital		22,798,000			22,749,000			22,710,000
Treasury stock (349,265 shares); at cost		(23,000	)		(23,000	)		(23,000	)
Accumulated deficit		(10,808,000	)		(12,571,000	)		(14,626,000	)
Total shareholders’ equity		11,984,000			10,172,000			8,078,000
Total liabilities and shareholders’ equity	$	20,690,000		$	15,452,000		$	11,850,000

See accompanying notes to consolidated financial statements.

21

Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

	Years Ended March 31,
	2008			2007			2006
				As Restated			As Restated
Revenues:
Oil and gas sales	$	7,415,000		$	7,129,000		$	6,595,000
Well service revenue		32,000			38,000			20,000
Total revenues		7,447,000			7,167,000			6,615,000
Expenses:
Oil and gas production		2,085,000			1,935,000			2,104,000
Production tax		621,000			487,000			460,000
Well servicing expenses		27,000			41,000			24,000
Depreciation, depletion and amortization		685,000			640,000			550,000
Accretion of asset retirement obligation		114,000			108,000			74,000
Asset retirement expense		35,000			125,000			63,000
General and administrative		716,000			546,000			524,000
Total expenses		4,283,000			3,882,000			3,799,000
Income from operations		3,164,000			3,285,000			2,816,000
Other Income (Expense):
Interest and other income		152,000			50,000			23,000
Fuel purchase overcharge refund		―			79,000			―
Interest and other expenses		(28,000	)		(7,000	)		(11,000	)
Total other income		124,000			122,000			12,000
Income before income taxes		3,288,000			3,407,000			2,828,000
Current income tax expense		179,000			326,000			13,000
Provision for deferred income taxes		1,346,000			1,026,000			482,000
Total income taxes		1,525,000			1,352,000			495,000
Net income	$	1,763,000		$	2,055,000		$	2,333,000
Per share amounts:
Basic	$	0.10		$	0.12		$	0.14
Diluted	$	0.10		$	0.12		$	0.14
Weighted average common shares outstanding:
Basic		17,370,256			16,825,076			16,732,611
Diluted		17,480,671			17,129,537			17,125,635

See accompanying notes to consolidated financial statements.

22

Basic Earth Science Systems, Inc.

Consolidated Statements of Shareholders’ Equity

Years Ended March 31, 2008, 2007, and 2006

	Common stock				Additional		Treasury stock				Accumulated
	Shares		Par value		paid-in capital		Shares		Amount		deficit		Total
As of  March 31, 2006 (as reported)		17,126,000	$	17,000	$	22,710,000		(349,000)	$	(23,000)	$	(14,144,000)	$	8,560,000
Cumulative effect of error corrections (Note 2)		—		—		—		—		—		(482,000)		(482,000)
As of  March 31, 2006 (as restated)		17,126,000	$	17,000	$	22,710,000		(349,000)	$	(23,000)	$	(14,626,000)	$	8,078,000
Stock options exercised		175,000		—		20,000		—		—		—		20,000
Net income (as reported)		—		—		—		—		—		2,500,000		2,500,000
As of March 31, 2007 (as reported)		17,301,000		17,000		22,730,000		(349,000)		(23,000)		(12,126,000)		10,598,000
Cumulative effect of error corrections (Note 2)		—		—		19,000		—		—		(445,000)		(426,000)
As of March 31, 2007 (as restated)		17,301,000		17,000		22,749,000		(349,000)		(23,000)		(12,571,000)		10,172,000
Stock options exercised		165,000		—		49,000		—		—		—		49,000
Net income		—		—		—		—		—		1,763,000		1,763,000
Balance as of  March 31, 2008		17,466,000	$	17,000	$	22,798,000		(349,000)	$	(23,000)	$	(10,808,000)	$	11,984,000

See accompanying notes to consolidated financial statements.

23

Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows

	Years Ended March 31,
		2008		2007		2006
Cash flows from operating activities:			As restated		As restated
Net income	$	1,763,000	$	2,055,000	$	2,333,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		685,000		640,000		550,000
Deferred tax liability		1,311,000		1,007,000		482,000
Additional paid in capital  associated with deferred tax expense		35,000		19,000		―
Accretion of asset retirement obligation		114,000		108,000		74,000
Change in:
Accounts receivable, net		(85,000)		54,000		(308,000)
Other assets		(63,000)		70,000		(86,000)
Accounts payable and accrued liabilities		(158,000)		321,000		(33,000)
Other		7,000		9,000		1,000
Net cash provided by operating activities		3,609,000		4,283,000		3,013,000
Cash flows from investing activities:
Oil and gas property		(587,000)		(1,703,000)		(4,271,000)
Support equipment		(16,000)		(38,000)		(8,000)
Insurance settlements		66,000		208,000		―
Proceeds from sale of oil and gas property and equipment		14,000		146,000		43,000
Other		(52,000)		(26,000)		(45,000)
Net cash used in investing activities		(575,000)		(1,413,000)		(4,281,000)
Cash flows from financing activities:
Proceeds from exercise of common stock options		14,000		20,000		9,000
Proceeds from borrowing		―		565,000		1,905,000
Debt payments		―		(1,010,000)		(1,460,000)
Net cash provided by (used in) financing activities		14,000		(425,000)		454,000
Cash and cash equivalents:
Increase in cash and cash equivalents		3,048,000		2,445,000		(814,000)
Balance, beginning of year		2,523,000		78,000		892,000
Balance, end of year	$	5,571,000	$	2,523,000	$	78,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	28,000	$	7,000	$	8,000
Cash paid for income tax	$	171,000	$	13,000	$	―
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	210,000	$	512,000	$	―
Additions to oil and gas also included in accrued liabilities	$	2,273,000	$	―	$	―

See accompanying notes to consolidated financial statements.

24

Basic Earth Science Systems, Inc.

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Organization and Nature of Operations. Basic Earth Science Systems, Inc. (“Basic” or “the Company” or “we” or “our” or “us”), 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.

Oil and Gas Producing Activity. We follow the full cost method of accounting for our oil and gas activity. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. Should net oil and gas property cost exceed an amount equal to the present value (using a 10% discount factor) of estimated future net revenue from proved reserves, considering related income tax effects, as prescribed by the Securities and Exchange Commission’s ceiling limitation, the excess is charged to expense during the period in which the excess occurs. We did not incur a ceiling limitation charge in either of the years ended March 31, 2008 or March 31, 2007.

If a significant portion of our oil and gas reserves are sold, a gain or loss would be recognized; otherwise, proceeds from sales are applied as a reduction of oil and gas property. In 2008 and 2007, we reduced the carrying value of our oil and gas property $14,000 and $146,000, respectively, as a result of the sale of its interest in certain oil and gas property and equipment. Also in 2008, we received insurance settlements of $66,000 related to blowout coverage. The carrying value of our oil and gas property was reduced by the $66,000 received from these settlements.   In 2007, we received insurance settlements of $161,000 and $47,000 related to contractor negligence coverage and blowout coverage, respectively. The carrying value of our oil and gas property was reduced by the $208,000 received from these settlements.

All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties we own. Depletion expense per equivalent barrel of production was $6.34 and $4.85 for 2008 and 2007, respectively.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of oil and gas reserves as well as the assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. There are many factors, including global events, which may influence the production, processing, marketing, and pricing 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. Estimates of oil and gas reserve quantities provide a basis for calculation of depreciation, depletion, and amortization expense, as well as the potential for impairment.

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 various methods 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. See also Notes 4 and 5 below.

25

Fair Value of Financial Instruments. Unless otherwise specified, we believe the carrying value of financial instruments approximates their fair value.

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 and certain intangibles are reported at the lower of cost or their estimated recoverable amounts. During 2008 and 2007, there was no impairment recorded for long-lived assets.

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 reflects the potential dilution of securities that could share in the earnings of the Company and 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. The following is a reconciliation of basic and diluted earnings per share for 2008 and 2007:

	Years Ended March 31,
	2008		2007
Numerator:			As restated
Net income available to common shareholders	$	1,763,000	$	2,055,000
Denominator:
Denominator for basic earnings per share		17,370,256		16,825,076
Effect of dilutive securities:
Stock options		110,415		304,461
Denominator for diluted earnings per share		17,480,671		17,129,537

All options currently issued and outstanding were included in the computation of diluted earnings per share for both 2008 and 2007. See Note 7 below for further discussion of our stock options.

Stock Option Plan. With the issuance of SFAS No. 123(R), Accounting for Share Based Compensation, effective December 2004, we are required to recognize all equity-based compensation, including stock option grants, as stock-based compensation expense in our Consolidated Statements of Operations based on the fair value of the compensation. No options have been granted since July 2003, and the plan expired in July 2005.  We did not record any stock-based compensation expense in either 2008 or 2007. See Note 8 below for further discussion of the Company’s stock options.

Comprehensive Income. Comprehensive income is comprised of net income and all changes to the Consolidated Statements of Shareholders’ Equity, except those due to investments by shareholders, changes in additional paid-in capital and distributions to shareholders. There was no difference between net income and comprehensive income for 2008 or 2007.

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.

26

Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” which requires the use of the “liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial statement and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. See Note 9 below.

Hedging Activities. We had no hedging activities in 2008 and 2007. Hedging strategies, or absence of hedging, may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events which we are not able to anticipate.

Major Customersand Concentration of Credit Risk.  Purchasers of 10% or more of our oil and gas production revenue for 2008 and 2007 are as follows:

	2008		2007
Plains Marketing LP	3	%	22	%
Murphy Oil USA, Inc.	22	%	20	%
Valero Energy	20	%	18	%
Nexen Marketing USA, Inc.	11	%	6	%
Texon LP	10	%	8	%
Total	66	%	74	%

It is not expected that the loss of any of these customers would cause a material adverse impact on operations since alternative markets for our products are readily available.

Reclassifications. Certain prior year amounts may have been reclassified to conform to current year presentation. Such reclassifications had no effect on the prior year net income, except as disclosed in Note 2.

Recent Accounting Pronouncements

In March 2007, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, An Amendment of FASB Statement No. 133.” SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, does not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. Accordingly, SFAS 161 requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The adoption of the provisions of SFAS 161 is not expected to have a material effect on our financial position, results of operations, or cash flows.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R will significantly change the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, research and development assets and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. SFAS 141R is effective for fiscal years beginning after December 15, 2008. The adoption of the provisions of SFAS 141R is not expected to have a material effect on our financial position, results of operations, or cash flows.

27

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, An Amendment of ARB No. 51.” SFAS 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling 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. The adoption of the provisions of SFAS 160 is not expected to 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.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 effective date of SFAS 159 for our Company is April 1, 2008.The adoption of the provisions of SFAS 159 is not expected to have a material effect on our financial position, results of operations, or cash flows.

In September2006, the FASB issued SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No.87, 106, and 132(R).” SFAS 158 requires companies to recognize a net asset for a defined benefit postretirement pension or healthcare plan’s over funded status or a net liability for a plan’s under funded status in its balance sheet. SFAS 158 also requires companies to recognize changes in the funded status of a defined benefit postretirement plan in accumulated other comprehensive income in the year in which the changes occur. SFAS 158 was adopted on March 31, 2007. Additionally, SFAS 158 requires companies to measure plan assets and benefit obligations as of the date of the fiscal year end balance sheet, which is consistent with our current practice. This requirement is effective for fiscal years ending after December15, 2008. The adoption of the provisions of SFAS 158 is not expected to have a material effect on our financial position, results of operations, or cash flows.

In September2006, 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 November15, 2007. The adoption of the provisions of SFAS 157 is not expected to have a material effect on our financial position, results of operations, or cash flows.

28

In July 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of SFAS 109”. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes”. FIN48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In addition, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard.Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized as an adjustment to the opening balance of retained earnings (or other appropriate components of equity) for that fiscal year.The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006.We adopted FIN 48 effective April 1, 2007.See Note 9, Income Taxes, for further discussion.

2. Restatement of Prior Period’s Financial Statements

During the fourth quarter of 2008, we identified errors in the accounting for certain tax liabilities and we determined the cumulative impact of known differences in our accounting as set forth below. The errors occurred in calculating the GAAP cost basis of our oil and gas properties in determining deferred tax liability and the estimated deferred tax asset for percentage depletion carryforward for both fiscal years under SFAS 109 - Accounting for Income Taxes. The gross cost of the oil and gas properties was reduced for the salvage value of the oil and gas equipment in the deferred tax calculation which reduced the deferred tax liability associated with our oil and gas properties in fiscal 2007 and 2006. The Company revised the estimated percentage depletion carryforward calculation for both fiscal years.  The Company also increased the deferred tax expense for the tax effect of stock options exercised in fiscal 2007.These errors are more fully described below.  In accordance with the provisions of Statement on Financial Accounting Standards No. 154 – “Accounting Changes and Error Corrections", we have restated our prior years’ financial statements.  Details of the restatements for fiscal years 2007 and 2006 are included below.

Restatement of Tax Liabilities

During the completion of our 2008 income tax provision, it was discovered that we had not properly reconciled our tax liabilities primarily related to differences between the net book basis and the net tax basis of our depreciable property, plant and equipment and other miscellaneous deferred tax liabilities.  The following tables detail the effect of the corrections to our previously reported income tax provisions for fiscal years 2007 and 2006:

	For the Year Ended March 31, 2007
	As reported			Adjustments			As restated
Federal income tax provision at statutory rates	$	1,161,000		$	―		$	1,161,000
State income tax		106,000						106,000
Change in valuation allowance		(359,000	)		359,000			―
Change in depletion carryforward		―			71,000			324,000
Change in book basis of oil and gas properties		―			107,000			107,000
Other		(1,000	)		(92,000	)		(93,000	)
Income tax expense	$	907,000		$	445,000		$	1,352,000

29

	For the Year Ended March 31, 2007
	As reported			Adjustments			As restated
Allowance for doubtful accounts	$	26,000		$	―		$	26,000
Asset retirement obligation		731,000			―			731,000
Other accruals		98,000			―			98,000
Statutory depletion carry-forward		1,244,000			(324,000	)		1,568,000
Total gross deferred tax assets		2,099,000			(324,000	)		2,423,000
Deferred tax liability - Depreciation, depletion and intangible drilling costs		(2,680,000	)		1,232,000			(3,912,000	)
Net deferred tax liability	$	(581,000	)	$	908,000		$	(1,489,000	)

	For the Year Ended March 31, 2006
	As reported			Adjustments			As restated
Federal income tax provision at statutory rates	$	993,000		$	―		$	993,000
State income tax		87,000			―			87,000
Change in valuation allowance		(819,000	)		(360,000	)		(1,179,000	)
Change in book basis of oil and gas properties		―			842,000			842,000
Other		(248,000	)		—			(248,000	)
Income tax expense	$	13,000		$	482,000		$	495,000

	For the Year Ended March 31, 2006
	As reported			Adjustments			As restated
Allowance for doubtful accounts	$	26,000		$	―		$	26,000
Asset retirement obligation		537,000			―			537,000
Other accruals		47,000			―			47,000
Statutory depletion carry-forward		1,897,000			―			1,897,000
Total gross deferred tax assets		2,507,000			―			2,507,000
Valuation allowance		(359,000	)		(359,000	)		―
Net deferred tax asset		2,148,000			(359,000	)		2,507,000
Deferred tax liability - Depreciation, depletion and intangible drilling costs		(2,148,000	)		841,000			(2,989,000	)
Net deferred tax liability	$	―		$	482,000		$	(482,000	)

Restatement of Financial Statements

The “Adjustments” column in the following tables reflects the effect of the corrections to our previously reported financial statements indicated above.

30

Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

	Year Ended March 31, 2007
	As Reported			Adjustments			As Restated
Revenues:
Oil and gas sales	$	7,129,000		$	―		$	7,129,000
Well service revenue		38,000			―			38,000
Total revenues		7,167,000			―			7,167,000
Expenses:
Oil and gas production		1,935,000			―			1,935,000
Production tax		487,000			―			487,000
Well servicing expenses		41,000			―			41,000
Depreciation, depletion and impairment		640,000			―			640,000
Accretion of asset retirement obligation		108,000			―			108,000
Asset retirement expense		125,000			―			125,000
General and administrative		546,000			―			546,000
Total expenses		3,882,000			―			3,882,000
Income from operations		3,285,000			―			3,285,000
Other Income (Expense):
Interest and other income		50,000			―			50,000
Fuel purchase overcharge refund		79,000			―			79,000
Interest and other expenses		(7,000	)		―			(7,000	)
Total other income		122,000			―			122,000
Income before income taxes		3,407,000			―			3,407,000
Current income tax expense		326,000			―			326,000
Provision for deferred income taxes		581,000			445,000			1,026,000
Total income taxes		907,000			445,000			1,352,000
Net income	$	2,500,000		$	(445,000	)	$	2,055,000
Per share amounts:
Basic	$	0.15		$	(0.03	)	$	0.12
Diluted	$	0.15		$	(0.03	)	$	0.12
Weighted average common shares outstanding:
Basic		16,825,076			16,825,076			16,825,076
Diluted		17,129,537			17,129,537			17,129,537

31

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31, 2007
	As Reported			Adjustments		As Restated
Assets
Current assets:
Cash and cash equivalents	$	2,523,000		$	―	$	2,523,000
Accounts receivable:
Oil and gas sales		825,000			―		825,000
Joint interest and other receivables, net of $70,000 allowance		436,000			―		436,000
Other current assets		262,000			―		262,000
Total current assets		4,046,000			―		4,046,000
Oil and gas property, full cost method:
Proved property		27,686,000			―		27,686,000
Unproved property		1,199,000			―		1,199,000
Accumulated depreciation and depletion		(17,842,000	)		―		(17,842,000	)
Net oil and gas property		11,043,000			―		11,043,000
Other non-current assets, net		363,000			―		363,000
Total non-current assets		11,406,000			―		11,406,000
Total assets	$	15,452,000		$	―	$	15,452,000

32

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31, 2007
	As Reported			Adjustments			As Restated
Liabilities
Current liabilities:
Accounts payable	$	744,000		$	―		$	744,000
Accrued liabilities		1,245,000			―			1,245,000
Total current liabilities		1,989,000			―			1,989,000
Long-term liabilities:
Long-term debt		―			―			―
Deferred tax liability		581,000			908,000			1,489,000
Asset retirement obligation		1,802,000			―			1,802,000
Total long-term liabilities		2,383,000			908,000			3,291,000
Commitments (Note 6)
Shareholders’ Equity
Preferred stock, $.001 par value Authorized - 3,000,000 shares Issued - 0 shares		―			―			―
Common stock, $.001 par value Authorized - 32,000,000 shares, Issued - 17,304,752 shares		17,000			―			17,000
Additional paid-in capital		22,730,000			19,000			22,749,000
Treasury stock (349,265 shares); at cost		(23,000	)		―			(23,000	)
Accumulated deficit		(11,644,000	)		(927,000	)		(12,571,000	)
Total shareholders’ equity		11,080,000			(908,000	)		10,172,000
Total liabilities and shareholders’ equity	$	15,452,000		$	―		$	15,452,000

33

Basic Earth Science Systems, Inc.

Consolidated Statement of Cash Flows

	Years Ended March 31, 2007
	As Reported			Adjustments			As Restated
Increase (decrease) in cash and cash equivalents:
Cash flows from operating activities:
Net income	$	2,500,000			(445,000	)	$	2,055,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		640,000			―			640,000
Deferred tax liability		581,000			426,000			1,007,000
Additional paid in capital  associated with deferred tax expense		―			19,000			19,000
Accretion of asset retirement obligation		108,000			―			108,000
Change in:
Net accounts receivable		54,000			―			54,000
Other assets		70,000			―			70,000
Accounts payable and accrued liabilities		321,000			―			321,000
Other		9,000			―			9,000
Net cash provided by operating activities		4,283,000			―			4,283,000
Cash flows from investing activities:
Capital expenditures:
Oil and gas property		(1,703,000	)		―			(1,703,000	)
Support equipment		(38,000	)		―			(38,000	)
Insurance settlements		208,000			―			208,000
Proceeds from sale of oil and gas property and equipment		146,000			―			146,000
Other		(26,000	)		―			(26,000	)
Net cash used in investing activities		(1,413,000	)		―			(1,413,000	)
Cash flows from financing activities:
Proceeds from exercise of common stock options		20,000			―			20,000
Proceeds from borrowing		565,000			―			565,000
Debt payments		(1,010,000	)		―			(1,010,000	)
Net cash provided by (used in) financing activities		(425,000	)		―			(425,000	)
Cash and cash equivalents:
Increase (decrease) in cash and cash equivalents		2,445,000			―			2,445,000
Balance, beginning of year		78,000			―			78,000
Balance, end of year	$	2,523,000		$	―		$	2,523,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	7,000		$	―		$	7,000
Increase in oil and gas property due to asset retirement obligation	$	512,000		$	―		$	512,000

34

Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

	Year Ended March 31, 2006
	As Reported			Adjustments			As Restated
Revenue
Oil and gas sales	$	6,595,000		$	―		$	6,595,000
Well service revenue		20,000			―			20,000
Total revenue		6,615,000			―			6,615,000
Expenses
Oil and gas production		2,104,000			―			2,104,000
Production tax		460,000			―			460,000
Well service expenses		24,000			―			24,000
Depreciation and depletion		550,000			―			550,000
Accretion of asset retirement obligation		74,000			―			74,000
Asset retirement expense		63,000			―			63,000
General and administrative		524,000			―			524,000
Total operating expenses		3,799,000			―			3,799,000
Income from operations		2,816,000			―			2,816,000
Other income (expense)
Interest and other income		23,000			―			23,000
Interest and other expenses		(11,000	)		―			(11,000	)
Total other income		12,000			―			12,000
Income before income taxes		2,828,000			―			2,828,000
Current income tax expense		13,000			―			13,000
Provision for deferred income taxes		―			482,000			482,000
Total income taxes		13,000			482,000			495,000
Net income	$	2,815,000		$	(482,000	)	$	2,333,000
Per share amounts:
Basic	$	0.17			(0.03	)	$	0.14
Diluted	$	0.17			(0.03	)	$	0.14
Weighted average common shares outstanding:
Basic		16,732,611			16,732,611			16,732,611
Diluted		17,125,635			17,125,635			17,125,635

35

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31, 2006
	As Reported			Adjustments		As Restated
Assets
Current assets:
Cash and cash equivalents	$	78,000		$	―	$	78,000
Accounts receivable:					―
Oil and gas sales		913,000			―		913,000
Joint interest and other receivables		472,000			―		472,000
Allowance for doubtful accounts		(70,000	)		―		(70,000	)
Other current assets		297,000			―		297,000
Total current assets		1,690,000			―		1,690,000
Property and equipment:
Oil and gas properties (full cost method)		27,138,000			―		27,138,000
Furniture, fixtures and support equipment		368,000			―		368,000
		27,506,000			―		27,506,000
Accumulated depreciation		(314,000	)		―		(314,000	)
Accumulated depreciation and depletion – Full cost pool		(17,250,000	)		―		(17,250,000	)
Net property and equipment		9,942,000			―		9,942,000
Other non-current assets		218,000			―		218,000
Total non-current assets		10,160,000			―		10,160,000
Total assets	$	11,850,000		$	―	$	11,850,000

36

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31, 2006
	As Reported			Adjustments			As Restated
Liabilities
Current liabilities:
Accounts payable	$	389,000		$	―		$	389,000
Accrued liabilities		1,084,000			―			1,084,000
Total current liabilities		1,473,000			―			1,473,000
Long-term liabilities:
Long-term debt		445,000			―			445,000
Deferred tax liability		―			482,000			482,000
Asset retirement obligation		1,372,000			―			1,372,000
Total long-term liabilities		1,817,000			482,000			2,299,000
Commitments (Note 6)
Shareholders’ Equity
Preferred stock, $.001 par value, Authorized - 3,000,000 shares, Issued - 0 shares		—			―			—
Common stock, $.001 par value, Authorized - 32,000,000 shares, Issued - 17,129,752 shares		17,000			―			17,000
Additional paid-in capital		22,710,000			―			22,710,000
Treasury stock (349,265 shares at March 31, 2005 and 2004); at cost		(23,000	)		―			(23,000	)
Accumulated deficit		(14,144,000	)		(482,000	)		(14,626,000	)
Total shareholders’ equity		8,560,000			(482,000	)		8,078,000
Total liabilities and shareholders’ equity	$	11,850,000		$	―		$	11,850,000

37

Basic Earth Science Systems, Inc.

Consolidated Statement of Cash Flows

	Year Ended March 31, 2006
	As Reported			Adjustments			As Restated
Increase (decrease) in cash and cash equivalents:
Cash flows from operating activities:
Net income	$	2,815,000		$	(482,000	)	$	2,333,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		550,000			―			550,000
Deferred tax liability		―			482,000			482,000
Accretion of asset retirement obligation		74,000			―			74,000
Change in:
Net accounts receivable		(308,000	)		―			(308,000	)
Other assets		(86,000	)		―			(86,000	)
Accounts payable and accrued liabilities		(33,000	)		―			(33,000	)
Asset retirement obligation		(6,000	)		―			(6,000	)
Other		7,000			―			7,000
Net cash provided by operating activities		3,013,000			―			3,013,000
Cash flows from investing activities:
Capital expenditures:
Oil and gas property		(4,271,000	)		―			(4,271,000	)
Support equipment		(8,000	)		―			(8,000	)
Purchase of lease and well equipment inventory		(45,000	)		―			(45,000	)
Proceeds from sale of oil and gas property and equipment		21,000			―			21,000
Proceeds from sale of lease and well equipment inventory		21,000			―			21,000
Proceeds from sale of support equipment		1,000			―			1,000
Net cash used in investing activities		(4,281,000	)		―			(4,281,000	)
Cash flows from financing activities:
Proceeds from exercise of common stock options		9,000			―			9,000
Proceeds from borrowing		1,905,000			―			1,905,000
Debt payments		(1,460,000	)		―			(1,460,000	)
Net cash provided by financing activities		454,000			―			454,000
Cash and cash equivalents:
Increase (decrease) in cash and cash equivalents		(814,000	)		―			(814,000	)
Balance, beginning of year		892,000			―			892,000
Balance, end of year	$	78,000		$	―		$	78,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	8,000		$	―		$	8,000

38

3. Asset Retirement Obligation

SFAS No. 143, “Accounting for Asset Retirement Obligations” requires the fair value of an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated present value of the asset retirement cost is capitalized as part of the carrying amount, and is included in the proved oil and gas properties in the accompanying consolidated balance sheets. We own oil and gas properties that require expenditures to plug and abandon when reserves in the wells are depleted. Under SFAS No. 143 these future expenditures are recorded in the period the liability is incurred (at the time the wells are drilled and completed or acquired).

The following table summarizes the activity related to our estimate of future asset retirement obligations for 2008, 2007, and 2006:

	Years Ended March 31,
	2008			2007			2006
Asset retirement obligation at beginning of period	$	1,971,000		$	1,408,000		$	1,263,000
Liabilities settled during the period		(116,000	)		(57,000	)		(61,000	)
New obligations for wells drilled and completed		84,000			—			29,000
Accretion of asset retirement obligation		114,000			108,000			74,000
Revisions to estimates		126,000			512,000			103,000
Asset retirement obligation at end of period	$	2,179,000		$	1,971,000		$	1,408,000
Current liability	$	302,000		$	169,000			36,000
Long-term liability		1,877,000			1,802,000			1,372,000
Asset retirement obligation at end of each period	$	2,179,000		$	1,971,000		$	1,408,000

The asset retirement expense recorded in years ended March 31, 2008 and 2007 represents plugging and abandonment costs in excess of the estimated asset retirement obligation recorded with the adoption of SFAS No. 143. We based our initial estimates on our knowledge and experience plugging wells in earlier years. The excess costs incurred over original estimates and the revisions to estimates shown in the table immediately above reflect the impact of escalating labor and rig costs primarily within the Williston basin area of North Dakota and Montana.

39

4. Other Current Assets

Other current assets at March 31, 2008, 2007, and 2006 consisted of the following:

	2008		2007		2006
Lease and well equipment inventory	$	154,000	$	159,000	$	161,000
Drilling and completion cost prepayments		52,000		50,000		118,000
Prepaid insurance premiums		58,000		47,000		12,000
Other current assets		16,000		6,000		6,000
Total other current assets	$	280,000	$	262,000	$	297,000

The lease and well equipment inventory represents well-site production equipment owned by us that has been removed from wells that we operate. This occurs when we plug a well or replace defective, damaged or suspect equipment on a producing well. In this case, salvaged equipment is valued at prevailing market prices, removed from the full cost pool and made available for sale. This equipment is carried on the balance sheet at a value not to exceed the original carrying value established at the time it was placed in inventory. This equipment is intended for re-sale to third parties at current fair market prices. Sale of this equipment is expected to occur in less than one year. This policy does not preclude us from further transferring serviceable equipment to other wells that we operate, on an as-needed basis.

Drilling and completion cost prepayments represent cash expenditures advanced by us to outside operators prior to the commencement of drilling and/or completion operations on a well.  The 2007 balance corresponds to the unused portion of cash advances on one North Dakota re-completion and on the Table Top Unit #1 well in the Company’s Christmas Meadows prospect while the 2008 balance was for the Lynn #1 and Lynn #2 wells, and the Table Top Unit #1 in North Dakota.

5. Other Non-Current Assets

Other non-current assets at March 31, 2008, 2007, and 2006 consisted of the following:

	2008		2007		2006
Lease and well equipment inventory	$	250,000	$	220,000	$	149,000
Plugging bonds		69,000		69,000		69,000
Other non-current assets		124,000		74,000		54,000
Total other non-current assets	$	443,000	$	363,000	$	272,000

This lease and well equipment inventory, unlike the equipment inventory in Other Current Assets that is held for re-sale, is intended for use on leases that we operate. This equipment inventory represents well-site production equipment that we own that has either been purchased or has been removed from wells that we operate. When placed in inventory, new equipment is valued at cost and salvaged equipment is valued at prevailing market prices. The inventory is carried at the lower of the original carrying value or fair market value.

Plugging bonds represent Certificates of Deposit furnished by us to third parties who supply plugging bonds to federal and state agencies where we operate wells.

40

6. 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 from December 31, 2007 to December 31, 2008. The current interest rate is prime plus one-quarter of one percent (0.25%) and the addition of an unused commitment fee equal to one-half of one percent (0.50%) per annum on the difference between the outstanding balance and the borrowing base amount.

Under the credit facility, we must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. With the December 31, 2006 amendment, the covenant requiring us to maintain a net worth of at least $1,750,000 was replaced with a covenant requiring us to maintain a debt-to-equity ratio less than one. Another covenant obligates us to maintain a current ratio of at least 1:1 inclusive of unused borrowing capacity and exclusive of the current portion of long-term debt. We were in compliance with all covenants at March 31, 2008.

This credit line is collateralized by a significant portion of our oil and gas properties and production. Our effective annual interest rate was 8.50% at March 31, 2008 and 2007. As of March 31, 2008, there was no outstanding balance on this line of credit.

During 2008, we did not utilize our credit facility, but during 2007 we utilized our credit facility to fund portions of our drilling and development program and incurred interest charges of $6,000. As of March 31, 2008 and 2007, there was no outstanding balance on the line of credit. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions, or pursue other opportunities we cannot contemplate at this time.

7. Commitments

Effective March 1, 2008 we relocated to a new 4,000 square foot office space located in downtown Denver, Colorado.  The lease agreement is for a five-year term through April 2013 and currently requires approximately $5,500 per month escalating at a rate of approximately $170 at the end of each year. Office rent expense was approximately $36,000 in both 2008 and 2007 and we are committed to a total of $281,000 for the five-year term ending April 1, 2013. Prior to expiration of the lease term, we will evaluate the Denver real estate market and the various available options before deciding on where to lease office space after April 2013.

8. Shareholders’ Equity

Preferred Stock. We have 3,000,000 shares of authorized preferred stock that can be issued in such series and preferences as determined by the Board of Directors.

Stock Option Plan. Effective July 27, 1995 our shareholders approved the 1995 Incentive Stock Option Plan (“the Plan”) authorizing option grants to employees and outside directors to purchase up to 1,000,000 shares of our common stock. The Plan was structured as a 10-year plan and, as such, ended on July 26, 2005. During the Plan’s existence, a total of 665,000 options were granted; of this amount, 50,000 options expired unexercised, 590,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share, and 25,000 options remain unexercised as of March 31, 2008 (see tables below).

Current option holders may exercise their options at the price of $0.1325 per share (which was the market value at the date of grant) over a period not to exceed ten years from the grant date provided they remain directors or employees of the Company.

41

A summary of the status of our stock option plan and outstanding options as of March 31, 2008, 2007, and 2006 and changes during the years ending on those dates is presented below:

		2008			2007			2006
			Weighted			Weighted			Weighted
			Average			Average			Average
			Exercise			Exercise			Exercise
	Shares		Price		Shares	Price		Shares	Price
Options unexercised, beginning of year		190,000	$	0.0936	365,000	$	0.1023	490,000	$	0.0954
Granted		—		—	—		—	—		—
Cancelled		—		—	—		—	—		—
Exercised		(165,000)		(0.0941)	(175,000)		(0.1117)	(125,000)		(0.0755)
Options unexercised and exercisable, end of year		25,000	$	0.1325	190,000	$	0.0936	365,000	$	0.1023

The 25,000 non-qualified stock options unexercised at March 31, 2008 had an intrinsic value of $24,000.

Since all options are fully vested, and the plan has expired, we will have no stock-based compensation expense in future periods unless a new plan is adopted and additional options are granted.

9. Income Tax

A reconciliation between the income tax provision at the statutory rate on income taxes and the income tax provision is as follows:

	For the Years Ended March 31,
	2008			2007
				As restated
Federal income tax provision at statutory rates	$	1,118,000		$	1,161,000
State income tax		164,000			106,000
Change in depletion carryforward		592,000			324,000
Change in book basis of oil and gas properties					107,000
Excess percentage depletion tax basis		(346,000	)		(253,000	)
Other		(3,000	)		(93,000	)
Income tax expense	$	1,525,000		$	1,352,000

42

The components of the net deferred tax assets and liabilities are shown below:

	For the Years Ended March 31,
	2008			2007
				As restated
Allowance for doubtful accounts	$	20,000		$	26,000
Asset retirement obligation		850,000			731,000
Other accruals		112,000			98,000
Statutory depletion carry-forward		1,043,000			1,568,000
Total gross deferred tax assets		2,025,000			2,423,000
Deferred tax liability - Depreciation, depletion and intangible drilling costs		(4,825,000	)		(3,912,000	)
Net deferred tax liability	$	(2,800,000	)	$	(1,489,000	)

As of March 31, 2008, we had fully utilized our net operating loss carry-forward for tax purposes.  We have statutory carryforwards of $1,043,000 that do not expire.

10. Related Party Transactions

It is our policy that officers or directors may assign to, or receive assignments from, us in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. It is also our policy that officers or directors and the Company may participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by each other. During 2008 and 2007 none of our officers or directors participated with the Company in any of our oil and gas transactions. In prior years, Ray Singleton, President of the Company, has participated with us in certain acquisitions. With respect to his working interest in the four wells in which he currently participates, at March 31, 2008 Mr. Singleton had a net credit balance of approximately $2,000 compared to $11,500 at March 31, 2007. This was due to his share of proceeds from the sale of well production equipment exceeding the amount due from him for his share of operating expenses. Also at March 31, 2008 and 2007, we had approximately $2,000 and $500 payables to him, respectively, for his share of net revenue from these wells.

11. Oil and Gas Property

The aggregate amount of capitalized costs related to oil and gas properties and the aggregate amount of related accumulated depreciation and depletion at March 31, 2008, 2007, and 2006 are as follows:

	2008			2007			2006
Proved property	$	29,035,000		$	27,686,000		$	24,257,000
Unproved property		2,515,000			1,199,000			2,881,000
		31,550,000			28,885,000			27,138,000
Accumulated depreciation and depletion		(18,515,000	)		(17,842,000	)		(17,250,000	)
Net capitalized oil and gas property	$	13,035,000		$	11,043,000		$	9,888,000

43

Costs directly associated with the acquisition and evaluation of unproved property are excluded from the full cost pool depreciation, depletion, and amortization computation until the properties can be classified as proved. These costs have been incurred over the last four fiscal years and are not yet evaluated as proved.  Upon proving these properties the costs will be reclassified as proved property, or in the event that a decision is made to cease operations on the property without further work estimated to be performed, the costs will be removed from unproved property and included in the full cost pool to be amortized.  Primarily, these costs relate to the following properties:

Antenna Federal. The 640 acre Antenna Federal property represents wells in progress totaling $1,250,000 (50%) of the 2008 unproved property total.  This field has been producing since 1988.  A recent, 16 well, down-spaced, development drilling effort, straddled the fiscal year end 2008, and we accrued the estimated drilling and completion cost, based on approved AFE’s, in that substantially all drilling and completion work had been completed and production equipment had been delivered.  However, 6 of the 11 wells in which we have a working interest were not on production at fiscal year end.  With no production information, the success of hydraulic stimulation on these wells was unknown.  In that these wells require hydraulic stimulation to produce, and that initial production is the best indicator of the success or failure of that stimulation effort, at year end no reserves were given to these wells and the wells remained unevaluated.  Since these wells are now on production, at this time, we would not consider them to be impaired in any way.

Banks Prospect. The Banks prospect consists of $790,000 (31%) of well costs related to the LM#1 well, and included in the unproved property total. We have a 20% interest in 13,000 gross acres, and have drilled three wells to-date: the State 16-1H, the LM #1 and the LM #2.  The initial well, the State 16-1H was successfully drilled and completed vertically in the Rival formation.  Next, the LM #1 was vertically drilled to the Rival formation, but was temporarily shut-in following an unsuccessful completion attempt.  Based on the results of the vertically-drilled LM #1, the LM #2 was horizontally drilled and successfully completed in the Rival formation.  Following the success of the LM #2, the vertical State 16-1H was re-entered and drilled horizontally. Both the State 16-1H and LM #2 are producing, and are included in the Ryder Scott reserves.  They indicate that horizontal drilling is the preferred solution in this heterogeneous reservoir.  Existing plans are to develop the remaining acreage, including that surrounding the LM #1 through this wellbore.  We own approximately 20% interest in this prospect.  Therefore, the timing and location of any further effort is and will be controlled by a majority of interest owners, not us.  Since only three wells have been drilled within the 13,000 acreage block, at this time, we would not consider this property to be impaired.

Christmas Meadows. Consists of $400,000 (16%) of the unproved property total and is only one well; the Table Top Unit #1, which has been drilled on the 40,000+ acreage Christmas Meadows prospect operated by Double Eagle Petroleum Company (“Double Eagle”).  The costs included in the table above comprise both the initial purchase of our 2% working interest in the joint venture and our share of drilling costs to-date for the Table Top Unit #1 well.  The well reached the originally planned depth of 15,760 feet, though it is not conclusive that the Dakota formation was encountered. The drill cuttings did not reveal reservoir rocks (due to either insufficient hydraulics to bring those cuttings to surface undamaged and intact, because they did not exist or because the Dakota was not reached).  A full suite of logs was not run because hole conditions prevented instruments from reaching the bottom of the well.  Operations were suspended to assess alternative approaches to completing the project. The wellbore was sealed with a drillable plug at 11,000 feet (the base of the intermediate casing) in order to prevent any abnormal pressure from migrating to surface.  The Table Top Unit, as originally formed, was dissolved.  Having met the governmental permitting obligation for the unit test well, the time-frame and leases have been extended for drilling the newly formed Main Fork Unit until at least April 2009.  Double Eagle has disclosed that it is in discussions with several larger or major companies to take over this venture and deepen this wellbore down to the deeper Nugget Sandstone at approximately 18,000 feet. Our small interest precludes us from controlling the timing or direction of this project. At this time, we do not consider this project to be impaired.

44

The following table shows, by category and date incurred, the oil and gas property costs applicable to unproved property that were excluded from the depreciation and depletion computation at March 31, 2008:

Costs Incurred During	Exploration		Development		Acquisition		Total Unproved
Year Ended	Costs		Costs		Costs		Property
March 31, 2008	$	68,000	$	1,248,000	$	—	$	1,316,000
March 31, 2007		308,000		104,000		—		412,000
March 31, 2006		428,000		335,000		—		763,000
March 31, 2005		24,000		—		—		24,000
Total	$	828,000	$	1,687,000	$	—	$	2,515,000

Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2008 and 2007 are summarized as follows:

	For the Years Ended March 31,
	2008		2007		2006
Development costs	$	2,410,000	$	1,017,000	$	2,881,000
Exploration costs		40,000		686,000		1,394,000
Acquisitions:
Proved		250,000		—		—
Unproved		—		—		—
Total	$	2,700,000	$	1,703,000	$	4,275,000

12. Unaudited Oil and Gas Reserves Information

At March 31, 2008, 2007, and 2006, 93%, 92%, and 93% respectively, of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company. The remaining 7 and 8 percent of the reserve estimates, respectively, were prepared internally by our management. We caution that there are many inherent uncertainties in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available, and these changes could be material.

The properties included in the oil and gas reserve estimates presented below contributed 97% of both our oil and gas production 2008. We have elected not to incur the additional expense of evaluating those properties that contributed the remaining 3% of both oil and gas production for inclusion in our estimated oil and gas reserves.

Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods.

45

Analysis of Changes in Proved Reserves. Estimated quantities of proved developed reserves (all of which are located within the United States), as well as the changes in proved developed reserves during the periods indicated, are presented in the following two tables:

Proved Developed Reserves

	Oil and Natural gas liquids		Natural gas
	(Bbls)		(Mcf)
Proved developed reserves at March 31, 2005		1,056,000		870,000
Revisions of previous estimates		(59,000)		152,000
Extensions and discoveries		55,000		89,000
Sales of reserves in place		—		—
Improved recovery		—		—
Purchase of reserves		—		—
Production		(100,000)		(141,000)
Proved developed reserves at March 31, 2006		952,000		970,000
Revisions of previous estimates		92,000		5,000
Extensions and discoveries		55,000		319,000
Sales of reserves in place		—		—
Improved recovery		—		—
Purchase of reserves		—		—
Production		(104,000)		(156,000)
Proved developed reserves at March 31, 2007		995,000		1,138,000
Revisions of previous estimates		112,000		(113,000)
Extensions and discoveries		19,000		203,000
Sales of reserves in place		—		—
Improved recovery		15,000		1,000
Purchase of reserves		22,000		—
Production		(89,000)		(109,000)
Proved developed reserves at March 31, 2008		1,074,000		1,120,000

All of our oil and gas reserves at March 31, 2008, 2007, and 2006 are classified as Proved Developed,

Producing.

The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to our proved oil and gas reserves. Estimated future cash inflows were computed by applying year end (March 31) prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves at March 31, 2008, 2007, and 2006. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

46

Standardized Measure of Estimated Discounted Future Net Cash Flows

	At March 31,
	2008			2007			2006
Future cash inflows	$	114,296,000		$	67,502,000		$	64,022,000
Future cash outflows:
Production cost		(49,599,000	)		(33,909,000	)		(29,618,000	)
Development cost		—			—			—
Future income taxes		(17,826,000	)		(8,070,000	)		(8,142,000	)
Future net cash flows		46,871,000			25,523,000			26,262,000
Adjustment to discount future annual net cash flows at 10%		(21,911,000	)		(10,899,000	)		(11,230,000	)
Standardized measure of discounted future net cash flows	$	24,960,000		$	14,624,000		$	15,032,000

The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for 2008, 2007, and 2006.

Changes in Standardized Measure of Estimated Discounted Net Cash Flows

	At March 31,
	2008			2007			2006
Standardized measure, beginning of period	$	14,624,000		$	15,032,000		$	14,819,000
Sales of oil and gas, net of production cost		(4,727,000	)		(4,707,000	)		(4,031,000	)
Net change in sales prices, net of production cost		14,598,000			(1,300,000	)		768,000
Discoveries, extensions and improved recoveries, net of future development cost		3,054,000			2,828,000			2,294,000
Change in future development costs		—			—			4,000
Development costs incurred during the period that reduced future development cost		—			—			—
Sales of reserves in place		—			—			—
Revisions of quantity estimates		2,639,000			1,404,000			(559,000	)
Accretion of discount		1,865,000			1,874,000			1,948,000
Net change in income taxes		(4,221,000	)		(317,000	)		957,000
Purchase of reserves		361,000			—			—
Changes in timing of rates of production		(3,233,000	)		(190,000	)		(1,168,000	)
Standardized measure, end of period	$	24,960,000		$	14,624,000		$	15,032,000

13. Quarterly Financial Data (Unaudited)

As discussed in Note 2 - Restatement of Prior Period’s Financial Statements, we have restated our annual results for fiscal years 2007 and 2006, as well as the quarterly periods therein to correct errors in our accounting for deferred tax liabilities.  We have also corrected the interim results for the first three quarters of fiscal 2008 for these same errors.  The amounts below have been restated to give effect of these corrections to the interim periods in 2008, 2007, and 2006.

47

Adjustments for Interim Periods during 2008.

Below is a summary of the balance sheet information from previously filed interim financial statements as affected by the restatement and adjustments for each of the quarterly periods ended June 30, 2007, September 30, 2007, December 31, 2007.

Consolidated Balance Sheet
(unaudited)	2008
	First Qtr			Second Qtr			Third Qtr
Assets
Total assets	$	15,669,000		$	16,774,000		$	19,190,000
Liabilities
Total current liabilities		1,603,000			1,934,000			3,159,000
Deferred Tax
Previously reported		746,000			986,000			1,340,000
Adjustment		1,033,000			1,158,000			1,283,000
As restated		1,779,000			2,144,000			2,623,000
Total Long Term Liabilities
Previously reported		2,574,000			2,791,000			3,408,000
Adjustment		1,033,000			1,158,000			1,283,000
As restated		3,607,000			3,949,000			4,691,000
Shareholders' Equity
Additional Paid in Capital
Previously reported		22,730,000			22,732,000			22,744,000
Adjustment		19,000			19,000			19,000
As restated		22,749,000			22,751,000			22,763,000
Total Shareholders Equity
Previously reported		11,492,000			12,049,000			12,623,000
Adjustment		(1,033,000	)		(1,158,000	)		(1,283,000	)
As restated		10,459,000			10,891,000			11,340,000
Total Liabilities and Equity	$	15,669,000		$	16,774,000		$	19,190,000

48

Adjustments for Interim Periods during 2008.

Below is a summary of the statement of operations information from previously filed interim financial statements as affected by the restatement and adjustments for each of the quarterly periods ended June 30, 2007, September 30, 2007, December 31, 2007.

Statement of Operations
(unaudited)	2008
	First Qtr			Second Qtr			Third Qtr
Total Revenue	$	1,614,000		$	1,794,000		$	2,081,000
Income before income taxes		627,000			845,000			941,000
Deferred Taxes
Previously reported		165,000			240,000			354,000
Adjustment		125,000			125,000			125,000
As restated		290,000			365,000			479,000
Total Income taxes
Previously reported		215,000			290,000			379,000
Adjustment		125,000			125,000			125,000
As restated		340,000			415,000			504,000
Net Income
Previously reported		412,000			555,000			562,000
Adjustment		(125,000	)		(125,000	)		(125,000	)
As restated	$	287,000		$	430,000		$	437,000

49

Adjustments for Interim Periods during 2007.

Below is a summary of the balance sheet information from previously filed interim financial statements as affected by the restatement and adjustments for each of the quarterly periods ended June 30, 2006, September 30, 2006, December 31, 2006 and March 31, 2007.

Consolidated Balance Sheet
(unaudited)	2007
	First Qtr			Second Qtr			Third Qtr			Fourth Qtr
Assets
Total assets	$	12,669,000		$	13,612,000		$	14,274,000		$	15,452,000
Liabilities
Total current liabilities		1,849,000			1,769,000			2,021,000			1,989,000
Deferred Tax
Previously reported		300,000			613,000			779,000			581,000
Adjustment		227,000			454,000			681,000			908,000
As restated		527,000			1,067,000			1,460,000			1,489,000
Total Long Term Liabilities
Previously reported		1,543,000			1,783,000			1,915,000			2,383,000
Adjustment		227,000			454,000			681,000			908,000
As restated		1,770,000			2,237,000			2,596,000			3,291,000
Shareholders' Equity
Additional Paid in Capital
Previously reported		22,710,000			22,713,000			22,713,000			22,730,000
Adjustment		4,750			9,500			14,250			19,000
As restated		22,714,750			22,722,500			22,727,250			22,749,000
Total Shareholders Equity
Previously reported		9,277,000			10,060,000			10,338,000			11,080,000
Adjustment		(227,000	)		(454,000	)		(681,000	)		(908,000	)
As restated		9,050,000			9,606,000			9,657,000			10,172,000
Total Liabilities and Equity	$	12,669,000		$	13,612,000		$	14,274,000		$	15,452,000

50

Adjustments for Interim Periods during 2007.

Below is a summary of the statement of operations information from previously filed interim financial statements as affected by the restatement and adjustments for each of the quarterly periods ended June 30, 2006, September 30, 2006, December 31, 2006 and March 31, 2007.

Statement of Operations
b  (unaudited)	2007
	First Qtr			Second Qtr			Third Qtr			Fourth Qtr
Total Revenue	$	1,984,000		$	2,062,000		$	1,585,000		$	1,536,000
Income before income taxes		1,034,000			1,103,000			679,000			591,000
Deferred Taxes
Previously reported		300,000			313,000			166,000			(198,000	)
Adjustment		111,250			111,250			111,250			111,250
As restated		411,250			424,250			277,250			(86,750	)
Total Income taxes
Previously reported		317,000			323,000			401,000			(134,000	)
Adjustment		111,250			111,250			111,250			111,250
As restated		428,250			434,250			512,250			(22,750	)
Net Income
Previously reported		717,000			780,000			278,000			725,000
Adjustment		(111,250	)		(111,250	)		(111,250	)		(111,250	)
As restated	$	605,750		$	668,750		$	166,750		$	613,750

51

Adjustments for Interim Periods during 2006.

Below is a summary of the balance sheet information from previously filed interim financial statements as affected by the restatement and adjustments for each of the quarterly periods ended June 30, 2005, September 30, 2005, December 31, 2005 and March 31, 2006.

Consolidated Balance Sheet
b  (unaudited)	2006
	First Qtr			Second Qtr			Third Qtr			Fourth Qtr
Assets
Total assets	$	9,561,000		$	10,169,000		$	10,545,000		$	11,850,000
Liabilities
Total current liabilities		2,114,000			2,079,000			1,690,000			1,473,000
Deferred Tax
Previously reported		―			―			―			―
Adjustment		120,500			241,000			361,500			482,000
As restated		120,500			241,000			361,500			482,000
Total Long Term Liabilities
Previously reported		1,162,000			1,155,000			1,118,000			1,817,000
Adjustment		120,500			241,000			361,500			482,000
As restated		1,282,500			1,396,000			1,479,500			2,299,000
Shareholders' Equity
Additional Paid in Capital
Previously reported		22,703,000			22,709,000			22,709,000			22,710,000
Adjustment		―			―			―			―
As restated		22,703,000			22,709,000			22,709,000			22,710,000
Total Shareholders Equity
Previously reported		6,285,000			6,935,000			7,737,000			8,560,000
Adjustment		(120,500	)		(241,000	)		(361,500	)		(482,000	)
As restated		6,164,500			6,694,000			7,375,500			8,078,000
Total Liabilities and Equity	$	9,561,000		$	10,169,000		$	10,545,000		$	11,850,000

52

Adjustments for Interim Periods during 2006.

Below is a summary of the statement of operations information from previously filed interim financial statements as affected by the restatement and adjustments for each of the quarterly periods ended June 30, 2005, September 30, 2005, December 31, 2005 and March 31, 2006.

Statement of Operations
(unaudited)	2006
	First Qtr			Second Qtr			Third Qtr			Fourth Qtr
Total Revenue	$	1,534,000		$	1,641,000		$	1,688,000		$	1,752,000
Income before income taxes		560,000			644,000			802,000			822,000
Deferred Taxes
Previously reported		―			―			―			―
Adjustment		120,500			120,500			120,500			120,500
As restated		120,500			120,500			120,500			120,500
Total Income taxes
Previously reported		13,000			―			―			―
Adjustment		120,500			120,500			120,500			120,500
As restated		133,500			120,500			120,500			120,500
Net Income
Previously reported		547,000			644,000			802,000			822,000
Adjustment		(120,500	)		(120,500	)		(120,500	)		(120,500	)
As restated	$	426,500		$	523,500		$	681,500		$	701,500

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ITEM 8

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 8A

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the "Exchange Act"), the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

The Chief Executive Officer and Principal Accounting Officer evaluated the effectiveness of the Company's disclosure controls and procedures and concluded that, following implementation of the changes in internal control over financial reporting discussed below, the Company's disclosure controls and procedures were effective as of March 31, 2008.

The restatement of our 2007 and 2006 financial statements, as contained in this Form 10-KSB, raise the question whether the original statements made by management concerning our disclosure controls and procedures and our internal control over financial reporting for 2007 and 2006 should be modified or supplemented so that such statements would not be misleading in light of these restatements. Based upon the Commission’s Guidance Regarding Management’s Report On Internal Control Over Financial Reporting Under Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (Release Nos. 33-8810, 34-55929, June 20, 2007), the restatement of financial statements does not, by itself, necessitate that management consider the effect of prior conclusions nor is management required to reassess and revise its prior conclusions. Nevertheless, management has reassessed these prior statements and has concluded that in 2007 and 2006 the Company had a material weakness in its internal control over income tax reporting with respect to calculating the GAAP cost basis of oil and gas properties in determining deferred tax liability and the estimated deferred tax asset for depletion carryforward, which were discovered in 2008.

Changes in Internal Control Over Financial Reporting

Anticipating the need to become compliant with Section 404 of the Sarbanes-Oxley Act of 2002 (SOX), during fiscal year 2008, we undertook a complete reassessment of our existing control and reporting procedures; and specifically our internal control over financial reporting.  Pursuant to this reassessment, we implemented a number of refinements and enhancements to include; better documentation, further definition of critical responsibilities and enhanced identification of critical control points.  These modifications had the effect of strengthening our existing controls and giving us a better overview of the interrelationships between various control processes.

In addition, in order to assist and enhance our efforts in maintaining effective controls over the completeness, accuracy and valuation of the accounting for and disclosure of income taxes, we engaged during the fourth quarter of the year a CPA firm to assist us as our principal tax advisors on an ongoing basis beginning for the year ended March 31st, 2008.  This CPA firm has assisted us in determining the restated valuations of deferred tax liabilities and demonstrated the appropriate level of knowledge, experience and training commensurate with our financial reporting requirements. 

54

Furthermore, in order to assist and enhance the Company’s efforts in maintaining effective internal controls over financial reporting, we engaged a Sarbanes-Oxley Section 404 consulting firm to assist us as our SOX advisors and internal auditors on an ongoing basis beginning for the year ended March 31st, 2008.  This consulting firm has assisted us in developing the enhancements and refinements necessary for management to reach its conclusions regarding its assessment of internal controls over financial reporting and has demonstrated the appropriate level of knowledge, experience and training commensurate with our financial reporting requirements. 

Other than the above, there were no changes in our internal control over financial reporting during the year ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Annual Report on Internal Control Over Financial Reporting

The management of Basic Earth Science Systems, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act.  This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements, and provide reasonable assurance as to the detection of fraud.

Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements.  Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.

With the participation of the Chief Executive Officer and Principal Accounting Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, the Company’s management concluded that the Company's internal control over financial reporting was effective as of March 31, 2008.

Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-KSB.  Therefore, this Annual Report on Form 10-KSB does not include such an attestation.

By: /s/ Ray Singleton	By: /s/ Joseph Young
Ray Singleton, President	Joseph Young
Chief Executive Officer	Principal Accounting Officer
July 11, 2008	July 11, 2008

55

ITEM 8B

OTHER INFORMATION

There is no information required to be disclosed on Form 8-K during the fourth quarter of the year ended March 31, 2008 that has not been reported.

56

Part III

ITEM 9

DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;

COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

Directors

The following sets forth the names and ages of the members of the Board of Directors of Basic Earth Science Systems, Inc. (“Basic” or “the Company” or “we” or “our” or “us”) who served during the past year, their respective principal occupations or employment during the past five years, and the period during which each has served as a director of the Company.

Ray Singleton(57) has been a director of Basic since July 1989. Mr. Singleton joined the Company in June 1988 as Production Manager/Petroleum Engineer. In October 1989 he was elected Vice President, and was appointed President and Chief Executive Officer in March 1993. Mr. Singleton began his career with Amoco Production Company in Texas as a production engineer. He was subsequently employed by the predecessor of Union Pacific Resources as a drilling, completion and production engineer and in 1981 began his own engineering consulting firm, serving the needs of some 40 oil and gas companies. As a consultant he was retained by the Company on various projects from 1981 to 1987. Mr. Singleton currently serves on the Board of Directors of the Independent Petroleum Association of Mountain States (IPAMS) and is a former president of that organization. IPAMS is a thirteen state, regional trade association that represents the interests of independent oil and gas companies in the Rocky Mountain region. In addition, Mr. Singleton is a member of the Society of Petroleum Engineers. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1973 and received a Masters Degree in Business Administration from Colorado State University’s Executive MBA Program in 1992.

David Flake (53) first became a director of the Company in September 1987. Mr. Flake began his career at Basic in November 1980 as tax accountant and was appointed Controller in July 1983. In September 1987 he was appointed Secretary/Treasurer and Chief Financial Officer. He held all of these positions at the Company until he resigned in January 1993 to pursue other business and financial opportunities. In April 1994 Mr. Flake was re-appointed Corporate Secretary. From September 1998 through December 2000 he provided financial consulting services to the Company. On January 1, 2001 Mr. Flake rejoined Basic as a full-time employee and was re-appointed Treasurer and Chief Financial Officer until he resigned in February 2008. Mr. Flake received his Bachelor of Science degree in Accounting/Business Administration from Regis University in Denver, Colorado in 1977 and his Masters Degree in Business Administration from Colorado State University’s Executive MBA Program in 1995.

Richard K. Rodgers (48) has been a director of Basic since December 2006. Mr. Rodgers was originally appointed to fill the vacancy created by the resignation of a prior director, and was then elected as a director at the Company’s shareholder meeting held on January 15, 2007. For the last 3 years, Mr. Rodgers has provided business development, planning and financial consulting services to various banking and business development clients. During the past five years, Mr. Rodgers was employed by several Denver area banks including Key Bank, Guaranty Bank & Trust Company and Colorado Capital Bank. In his most recent employment with Colorado Capital Bank from 2004 to 2005, he was the President, and was responsible for the start-up, of its Cherry Creek branch office and served on the board of directors of Colorado Capital Bank. Mr. Rodgers attended the University of Denver and received his Bachelor of Science degree in International Business Administration in 1995 and his Master of Science degree in International Business Administration in 1997.

57

Monroe W. Robertson(58)  was originally appointed to fill the vacancy created when the board, on April 4, 2007, amended the Company’s Bylaws to increase the number of members of the Board from three (3) members to four (4) members. Subsequently, he was elected as a director at the Company’s shareholder meeting held on January 21, 2008. Mr. Roberston currently serves on the Board of Directors of Cimarex Energy Company and is chairman of that board’s Audit Committee. Mr. Robertson began his career in 1973 with Gulf Oil Corporation and held various positions in engineering, corporate planning and financial analysis until 1986. From 1986 to 1992 he held various positions at Terra Resources and Apache Corporation. In 1992 Mr. Robertson joined Key Production Company as its Senior Vice President and Chief Financial Officer. In 1999 he was appointed President and Chief Operating Officer of that company and served in that role until 2002. Other than his service on Cimarex’s board which began in October 2005, for the past five years Mr. Robertson has been a private investor. Mr. Robertson received a Bachelor of Science degree in Mechanical Engineering along with Master of Science degrees in both Mechanical Engineering and Nuclear Engineering from the Massachusetts Institute of Technology in 1973. He also has received a Masters Degree in Business Administration from National University in 1979. Mr. Robertson is a member of the National Association of Corporate Directors.

Executive Officers

During the past year, until Mr. Flake resigned as an officer of the Company in February 2008, the Company’s executive officers were Ray Singleton and David Flake.  Both were also board members. Their names, ages, principal occupations and/or employment during the past five years are set forth above. There are no family relationships between or among the officers and Board of Directors.

Directors are elected by the Company’s shareholders at each annual meeting or, in the case of a vacancy, are appointed by the directors then in office, to serve until the next annual meeting or until their successors are elected and qualified. Officers are appointed by and serve at the discretion of the Board of Directors. There are no family relationships between or among the Board of Directors.

Involvement in Certain Legal Proceedings

During the past five years, no present director or executive officer of the Company has been the subject matter of any of the following legal proceedings: (a) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (b) any criminal convictions; (c) any order, judgment, or decree permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or (d) any finding by a court, the SEC or the CFTC to have violated a federal or state securities or commodities law.  Further, no such legal proceedings are believed to be contemplated by governmental authorities against any director or executive officer.

Corporate Governance

Independent Directors. Each of the Company’s directors, except for Messrs. Singleton and Flake, qualifies as an “independent director” as defined under the published listing requirements of the American Stock Exchange. The independence definition includes a series of objective tests. For example, an independent director may not be employed by Basic and may not engage in certain types of business dealings with the Company. In addition, the Board has made a subjective determination as to each independent director that no relationship exists, which in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the Board reviewed and discussed information provided by the directors and by the Company with regard to each director’s business and personal activities as they may relate to the Company and its management. Also, the Board determined that the members of the Audit Committee each qualify as “independent” under special standards established by the American Stock Exchange and the SEC for members of audit committees.

58

Audit Committee. The Board of Directors has a standing Audit Committee which, at March 31, 2008, consisted of Richard Rodgers and Monroe Robertson. During fiscal 2008 the Audit Committee met four times. The Audit Committee is authorized to review, with the Company’s independent accountants, the annual financial statements of the Company prior to publication and to make annual recommendations to the Board for the appointment of independent public accountants for the ensuing year. It is the responsibility of the Audit Committee to review the effectiveness of the financial and accounting functions, operations, and internal controls implemented by Basic’s management.

The Board has certified both Mr. Robertson and Mr. Rodgers as financially literate, and Mr. Robertson as an “audit committee financial expert,” as defined under Item 407(d)(5) of Regulation S-B under the Exchange Act. Both Mr. Robertson and Mr. Rodgers are considered “independent directors” under the listing standards of the American Stock Exchange.

Compensation Committee. The Board of Directors has a standing Compensation Committee which, at March 31, 2008, consisted of Richard Rodgers and Monroe Robertson, both of whom are independent under the guidelines of the American Stock Exchange listing standards. Mr. Rodgers serves as the Committee’s chairman. The responsibilities of the Compensation Committee (the “Committee”) of the Board of Directors are three-fold: first, establishing and administering the general compensation policies of the Company, second, setting the specific compensation for the Company’s chief executive officer (CEO) and lastly, recommending to the Board of Directors the independent director compensation.

No interlocking relationship exists between the members of the Company’s Board of Directors or Compensation Committee and the board of directors or compensation committee of any other company.

Nominating Committee. The Board of Directors has a standing Nominating Committee which, at March 31, 2008, consisted of Richard Rodgers and Monroe Robertson.

No material changes have been made to the procedures by which security holders may recommend nominees to the Board of Directors since we filed with the Securities and Exchange Commission, on December 13, 2007, its  definitive proxy statement for the 2007 Annual Meeting of Shareholders.

Code of Ethics. We have adopted a Code of Ethics as defined in Item 406 of Regulation S-B that applies to its directors, principal executive and financial officer and persons performing similar functions. The Code of Ethics can be found on our website at http://www.basicearth.net.

Compliance with Section 16(a) of the Securities Exchange Act

Section 16(a) of the Securities Exchange Act requires the Company’s officers and directors and shareholders of more than ten percent of the Company’s common stock to file reports of ownership and changes in ownership of the Company’s common stock with the Securities and Exchange Commission (SEC). Officers and directors are required by SEC regulations to furnish Basic with the information necessary for the Company to file all required Section 16(a) reports. During fiscal 2008 all required reports were filed timely.

59

ITEM 10

EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the compensation paid or accrued by the Company to its Chief Executive Officer and Chief Financial Officer for fiscal 2008 and 2007. No other director, officer or employee received annual compensation that exceeded $100,000.

						Non-Equity			All
Name and	Fiscal	Salary		Bonus		Incentive Plan			Other			Total
Principal Position	Year	($)		($)		Compensation			Compensation			($)
				(1)		(2)			(3)
Ray Singleton	2008	$	134,250	$	6,346		$	4,053		$	6,176	$	150,825
President and Chief Executive Officer	2007	$	102,183	$	3,981		$	5,983		$	4,031	$	116,178
David Flake	2008	$	85,574	$	24,240		$	3,205		$	4,084	$	117,103
Secretary/Treasurer,	2007	$	90,798	$	3,562		$	4,731		$	3,119	$	102,210
Former Chief Financial Officer and Controller

(1)	The amount shown for each executive officer is the amount accrued for in prior periods and paid in fiscal 2008.
(2)	The amount shown for each executive officer is the amount accrued for fiscal 2008 and paid for fiscal 2007 through the Oil and Gas Incentive Compensation Plan.
(3)	For Mr. Singleton, amount includes matching funds contributed by the Company to its 401(k) plan of $5,204 and $3,254 for fiscal 2008 and 2007, respectively. It also includes $850 and $777 for premiums paid by the Company on a life insurance policy for Mr. Singleton during fiscal 2008 and 2007, respectively. Mr. Singleton designates the beneficiary. For Mr. Flake, the Company’s former CFO, all amounts were for matching funds contributed by the Company to its 401(k) plan for his benefit.

Effective April 1, 1980 the Company adopted an Oil and Gas Incentive Compensation Plan (the O&G Plan) for key employees. Through this O&G Plan, Basic pays to the O&G Plan participants, consisting of both former and current key employees, a portion of its net revenue (after deducting operating expenses) from certain properties. Under the O&G Plan rules, the portion of the net revenue contributed from any property cannot exceed 5% of the Company’s interest in that property. While payments are still made to the O&G Plan participants due to previous grants, the last time a new property was added to the O&G Plan was in 1988.

The participants in the O&G Plan made no cash outlay at the time of grant in order to participate; it was entirely non-contributory, and an interest is not assignable, transferable, nor can it be pledged by the participant. Interest in the O&G Plan vested over a period ranging from four to eleven years. We can sell or otherwise transfer its interest in properties designated for the O&G Plan. If we sell a property in the O&G Plan, the participants shall receive their respective percentages of the sales price. There are currently five participants in the O&G Plan including Messrs. Singleton and Flake, our former CFO. The other three participants are former officers who have vested interests in the O&G Plan ranging from 60 percent to 100 percent. Compensation paid or accrued through this plan to Messrs. Singleton and Flake is included in the Other Annual Compensation column in the Executive Officer Compensation table above.

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On July 27, 1995 the Board of Directors adopted the 1995 Incentive Stock Option Plan (the ISO Plan) and in October 1995, our shareholders approved the ISO Plan. The ISO Plan remained in effect for a period of ten years, expiring on July 26, 2005. This ISO Plan was established to provide a flexible and comprehensive stock option and incentive plan which permitted the granting of long-term incentive awards to employees, including officers and directors employed by us or our subsidiary, as a means of enhancing and strengthening our ability to attract and retain those individuals on whom the continued success of the Company most depends.

Of the 1,000,000 shares authorized under the ISO Plan, prior to its expiration, options for only 665,000 shares were granted. Of that amount and as of March 31, 2008, 50,000 options expired unexercised, 590,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share, and 25,000 options remain unexercised.

In October 1997 we implemented a savings plan that allows participants to make contributions by salary reduction pursuant to Section 401(k) of the Internal Revenue Code. Employees are required to work for the Company one year before they become eligible to participate in the 401(k) Plan. The Company matches 100% of the employee’s contribution up to 3% of the employee’s salary. Contributions are vested when made. Contributions to the 401(k) Plan on behalf of Messrs. Singleton and Flake, our former CFO, are also included in the All Other Compensation column in the Summary Compensation Table above.

Outstanding Equity Awards at Fiscal Year End

The following table provides information on the current stock option holdings by each of the named executive officers and directors as of March 31, 2008. The table below includes unexercised stock options related to director compensation for David Flake who is no longer an officer of the Company, but continues to retain his stock options as a director.

	Option Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: (#) of Securities Underlying Unexercised Unearned Options (3)		Option Exercise Price		Option Expiration Date
David Flake		25,000		—		N/A	$	0.133		7/26/2010

We have no contract with any officer which would give rise to any cash or non-cash compensation resulting from the resignation, retirement or any other termination of such officer’s employment with the Company or from a change in control of the Company or a change in any officer’s responsibilities following a change in control.

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Director Compensation

Prior to fiscal 2008, directors received no cash compensation for their services to the Company as directors, but were reimbursed for out-of-pocket expenses incurred to attend board meetings. However, from July 1995 until its expiration in July 2005, the Incentive Stock Option Plan (“the ISO Plan”), noted above, provided eligible, non-employee members of the Board of Directors of Basic or its subsidiaries (Non-Employee Directors), grants of certain options to purchase common stock of the Company, as compensation for their services. During the years the ISO Plan was active, 425,000 non-qualified options were granted to independent directors: 250,000 to Edgar Huffman and 175,000 to David Flake, our former CFO, who was then an independent director. As of March 31, 2008, Mr. Flake has 25,000 unexercised non-qualified options.

On March 8, 2007 the Board of Directors adopted a new Director Compensation Plan. On April 12, 2007 the Board of Directors resolved issues concerning the Plan and then ratified the Plan effective April 1, 2007.

With respect to this Plan, independent director compensation consists of a cash retainer, meeting fees, committee fees and stock grants. Independent directors receive an annual cash retainer of $16,000, in addition to $2,000 and $500 for quarterly board meetings and committee meetings (which take place as needed), respectively. Committee chairpersons of the Audit, Compensation, and Nominating Committees receive $5,500, $4,500 and $3,500, respectively. Additionally, independent board members receive an annual stock grant equal to $36,000 vested over three years. The number of shares included in each grant is determined based upon the average closing price of the ten trading days preceding each April 1st anniversary date. Thus, effective April 1, 2007 and April 1, 2008, subject to vesting, Messrs. Robertson and Rodgers are entitled to stock grants of 22,713 and 36,036 shares each, respectively.

Name	Fees Earned or Paid in Cash ($)			Stock Awards ($)					All Other Compensation ($)			Total ($)
					(1	)
Richard Rodgers		$	29,000				$	36,000		$	—		$	65,000
Monroe Robertson			28,000					36,000			—			64,000
Total			57,000					72,000			—			129,000

(1) The amount shown for each director is the amount awarded each year vesting over a three year period.

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ITEM 11

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Set forth below, as of July 11, 2008, is information concerning stock ownership of all persons, or group of persons, known by the Company to own beneficially 5% or more of the shares of Basic’s common stock and all directors and executive officers of the Company, both individually and as a group, who held such positions in fiscal 2008. Basic has no knowledge of any other persons, or group of persons, owning beneficially more than 5% of the outstanding common stock of the Company as of March 31, 2008.

Name and Address of Beneficial Owner	Type and Class	Shares of Common Stock Beneficially Owned		Percent of Outstanding Shares Beneficially Owned
Ray Singleton, Denver CO (a)	Common Stock		4,505,912		25.8	%
David Flake, Denver CO (b)	Common Stock		758,535		4.3	%
Richard Rodgers, Denver, CO (c)	Common Stock		7,571		(e	)
Monroe W. Robertson, Denver, CO (d)	Common Stock		13,471		(e	)
All officers and directors as a group	Common Stock		5,285,489		30.3	%
(4 persons) (a), (b), (c) and (d)

(a)	All 4,505,912 shares are owned directly by Mr. Singleton.
(b)	Represents 719,849 shares owned directly by Mr. Flake, the Company’s former CFO, and 38,686 shares with indirect beneficial ownership.
(c)	All 7,571 shares are fully vested and owned direclty by Mr. Rodgers.
(d)	All 13,471 shares are fully vested and owned directly by Mr. Robertson.
(e)	Less than 1%

Company management knows of no arrangements that may result in a change in control of Basic.

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ITEM 12

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

It is Company policy that officers or directors may assign to or receive assignments from Basic in oil and gas prospects only on the same terms and conditions as accepted by independent third parties. It is also the policy of Basic that officers or directors and Basic may participate together in oil and gas prospects generated by independent third parties only on the same terms and conditions as accepted by each other.

With respect to prospects initiated during either fiscal 2008 or 2007, none of Basic’s officers or directors participated with the Company. However, in previous years, Mr. Singleton participated with the Company in certain acquisitions. With respect to his working interest in the four wells in which he currently has a working interest, at March 31, 2008 Mr. Singleton had a net credit balance of approximately $2,000 compared to $11,500 at March 31, 2007. This was due to his share of proceeds from the sale of well production equipment exceeding the amount due from him for his share of operating expenses. Also at March 31, 2008 and 2007, the Company had approximate $2,000 and $500 payables to him, respectively, for his share of net revenue from these wells.  During fiscal 2008 and 2007 there were no other material related party transactions.

ITEM 13

EXHIBITS AND REPORTS ON FORM 8-K

Exhibits

Exhibit No.	Document
3i1	Restated Certificate of Incorporation included in Basic’s Form 10-K for the year ended March 31, 1981
3i1	By-laws included in Basic’s Form S-1 filed October 24, 1980
3i1	Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996
10(i)a1	Loan Agreement between The Bank of Cherry Creek and Basic, dated March 4, 2002
10(i)a1	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.
10(i)a1	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated December 31, 2006
10(ii)1	Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985
10(ii)1	Restricted Stock Agreement dated effective as of April 7, 2007
211	Subsidiaries of Basic included in Basic’s Form 10-KSB for the year ended March 31, 2002
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).

1 Previously filed and incorporated herein by reference

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.

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ITEM 14

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table discloses the fees that the Company was billed for professional services rendered by its independent public accounting firm, Hein & Associates LLP (Hein), in each of the last two fiscal years.

	Years Ended March 31,
	2008		2007
Audit fees (1)	$	70,000	$	50,953
Audit-related fees(2)		—		2,125
Tax fees(3)		11,500		10,000
All other fees(4)		—		—
Total	$	81,500	$	63,078

(1)	Reflects fees billed for the audit of the Company’s consolidated financial statements included in its Form 10-KSB and review of its quarterly reports on Form 10-QSB, which represents a 37.3% increase over the prior year.
(2)	Reflects fees, if any, for consulting services related to financial accounting and reporting matters.
(3)	Reflects fees billed for tax compliance, tax advice and preparation of the Company’s federal tax return.
(4)	Reflects fees, if any, for other products or professional services not related to the audit of the Company’s consolidated financial statements and review of its quarterly reports, or for tax services.

Pre-Approval Policies and Procedures

The Audit Committee approves all audit, audit-related services, tax services and other services provided by Hein. Any services provided by Hein that are not specifically included within the scope of the audit must be pre-approved by the Audit Committee in advance of any engagement. Under the Sarbanes-Oxley Act of 2002, audit committees are permitted to approve certain fees for audit-related services, tax services and other services pursuant to a de minimus exception prior to the completion of an audit engagement. In fiscal 2008, none of the fees paid to Hein were approved pursuant to the de minimus exception.

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Signatures

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

BASIC EARTH SCIENCE SYSTEMS, INC.

	Date
By: /s/ Ray Singleton	July 11, 2008
Ray Singleton, President
By: /s/ Joseph Young	July 11, 2008
Joseph Young,
Principal Accounting Officer

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name and Capacity	Date
By: /s/ Ray Singleton	July 11, 2008
Ray Singleton, Director
By: /s/ David Flake	July 11, 2008
David Flake, Director
By: /s/ Richard K. Rodgers	July 11, 2008
Richard K. Rodgers, Director and
Compensation Committee Chairman
By: /s/ Monroe W. Robertson	July 11, 2008
Monroe W. Robertson, Director and
Audit Committee Chairman