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, 2006

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.

1801 Broadway, Suite 620
Denver, Colorado 80202-3835
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: $6,615,000

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of a specified date within the past 60 days. (See definition of affiliate in Rule 12b-2 of the Exchange Act.)                    

As of June 21, 2006 16,780,487 shares of the registrant’s common stock were outstanding and the aggregate market value of such common stock held by non-affiliates was approximately $23,197,000. The proxy statement for the 2006 annual meeting is incorporated by reference into Part III.

Basic Earth Science Systems, Inc.

Form 10-KSB

March 31, 2006

Table of Contents

	Page
Part I:
Item 1. Description of Business	3
Item 2. Description of Property	13
Item 3. Legal Proceedings	15
Item 4. Submission of Matters to a Vote of Security Holders	15
Part II:
Item 5. Market for Common Equity and Related Stockholder Matters	16
Item 6. Management’s Discussion and Analysis and Plan of Operation	16
Item 7. Consolidated Financial Statements	26
Item 8. Changes In and Disagreements with Accountants On Accounting and Financial Disclosure	44
Item 8A. Controls and Procedures	44
Part III:
Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance With Section 16(a) of the Exchange Act	44
Item 10. Executive Compensation	44
Item 11. Security Ownership of Certain Beneficial Owners and Management	45
Item 12. Certain Relationships and Related Transactions	45
Item 13. Exhibits and Reports on Form 8-K	45
Item 14. Principal Accountant Fees and Services	46
Loan Agreement
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

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Part I

ITEM 1

DESCRIPTION OF BUSINESS

Overview

Basic Earth Science Systems, Inc. (Basic or the Company) is an independent oil and gas exploration company focusing on the fundamentals of company growth and profitability in an effort to enhance shareholder wealth. Basic is engaged in the exploration, acquisition, development, operation, production and sale of crude oil and natural gas. The Company has an established production base that generates positive cash flow and profits. The Company is comprised of seasoned industry professionals who have been associated with Basic for nearly two decades. These professionals have a management track record in both good times and bad. Capitalizing on their knowledge, the Company’s 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

Basic intends to enhance shareholder wealth by focusing on the fundamental value of the Company, i.e. reserve growth and profitability.

The three components of its 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.

While Basic has a three-pronged strategy to grow its pool of oil and gas reserves, its primary emphasis is exploration and development drilling. This emphasis, adopted in the fiscal year ended March 31, 2002, follows a decade of pursuing a property acquisition strategy. Basic’s primary exploration focus is in the Montana and North Dakota portions of the Williston basin. Second only to south Texas in terms of time frame, the Company has been involved in the Williston basin since the early 1980’s. As such, the Company has significant understanding of and exposure to both geology and operations in the area. However, both the Williston basin and the Company’s south Texas waterfloods are primarily oil productive. Sensitive to the need to increase its natural gas output and balance its product base, Basic’s efforts in other areas, notably Colorado and on-shore portions of the Gulf Coast, are simply to increase the Company’s exposure to natural gas projects.

In the past, the Company’s strategy focused on the acquisition of producing properties with subsequent enhancement and exploitation. With oil prices in the $50-$65 per barrel range, Basic believes that the price risk associated with property acquisitions is substantial. Thus, Basic has significantly curtailed its acquisition efforts relative to previous years. Despite this, the Company expects to monitor the acquisition market and, if economically feasible, attempt to procure properties that may augment existing operations or ownership.

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Areas of Focus

Williston Basin

The Company had three major areas of focus within the Williston basin during the year ended March 31, 2006 (fiscal 2006) and expects that focus to continue in the coming months. These areas are the horizontal Bakken play in Richland County, Montana, the Company’s efforts in the Indian Hill Field in McKenzie County, North Dakota and the Company’s Banks prospect in McKenzie County, North Dakota.

Horizontal Bakken — Richland County, Montana. By virtue of its acquisitions in the mid- and late-1990’s, the Company has interests in the heart of the horizontal Bakken play in Richland County, Montana. With interests in five different sections, Basic was originally exposed to several significant drilling opportunities. Two of these have now been developed; the very successful Halvorsen wells and the Johnson 3-21H (see discussion below). With better understanding of the Bakken in this area, the attractiveness of two other sections has been downgraded due to the quantity of oil already produced by vertical Bakken wells on this acreage. Thus, one remaining section could be developed where Basic has an interest. Basic’s actual working interest in such a development would be dependent upon the size of the approved well spacing unit and could range from a 12.5% to 25% working interest in one or two wells. At these levels, Basic’s financial commitment would vary from $450,000 to $900,000 per well.

Indian Hill Field — McKenzie County, North Dakota. In the year ended March 31, 2005 (fiscal 2005), Basic acquired an 18% interest in a 2,000 acre block within the Indian Hill Field. In fiscal 2005 and 2006 the Company participated in drilling three wells on this block and established production in both the Nisku and Duperow formations (see discussion below). Basic believes that, in addition, both the lower Mission Canyon and Rival formations may be productive not only in these wellbores but also on the surrounding undeveloped acreage. Basic and its partners expect to evaluate this potential in the current fiscal year.

Banks Prospect — McKenzie County, North Dakota. During the June 2005 quarter, the Company acquired a 20% interest in 13,000 acres in its Banks prospect in McKenzie County, North Dakota. Originally planned to position the Company in the developing, though unproven, extension of the Bakken horizontal play into North Dakota, the prospect is now headed in a different direction. When indications on its first horizontal Bakken well, the State 16-1H, were not encouraging, the Company and its partners elected to pursue development of the Rival formation. Including the State 16-1H, Basic drilled three wells on this prospect in fiscal 2006: a vertical Rival producer, a horizontal Rival producer (both of which remain unstimulated) and a temporarily abandoned well which is still being evaluated for further development (see discussion below). Basic and its partners expect to evaluate alternative stimulation protocols in an effort to enhance production from not only these existing wellbores, but also those that Basic drills on this acreage in the future. While the primary focus in this area is now the Rival formation, Basic still owns rights to the underlying Bakken formation and has one wellbore, the State 16-1H, that has a horizontal Bakken section that could be exploited. However, until such time as either offset Bakken production is demonstrated or a breakthrough in stimulation technology or application is made, Basic and its partners have little interest in pursuing Bakken development in this immediate area.

Onshore Gulf Coast

During fiscal 2006, the Company participated in three wells in this area: an 11,000 foot vertical Yegua formation drilling test in Wharton County, Texas, a 13,000 foot lower Frio formation recompletion in Matagorda County, Texas and a 14,000 foot Discorbis formation re-entry in St. Mary Parish, Louisiana. As noted above, the Company’s involvement in these efforts was pursued strictly to enhance Basic’s exposure to natural gas

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projects. Despite some setbacks (see discussion below), Basic is still interested in Yequa “3-D Bright Spot” prospects and intends to look at and evaluate other ventures in this area for possible future participation. However, the Company’s future involvement in this area will depend on the quality of prospects it reviews, the operational record of designated operators and the risk associated with specific ventures.

Other Areas

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

Denver-Julesberg Basin — Weld County, Colorado. On its Antenna Federal property the Company owns a 60% working interest in 7 wells producing from the J-Sand formation and an overriding royalty interest in 9 wells producing from the Codell-Niobrara formation in the D-J basin. For several years, Basic and its partner have been deepening the Codell wells to the J-Sand formation. Basic has a 3% to 5% overriding royalty interest in these Codell wells and earns a 60% working interest in the J-Sand production once a well is deepened to that formation. In addition, once a well is completed in the J-Sand, Basic takes over as operator of that well.

Christmas Meadows Prospect – Summit County, Utah. In the March 2006 quarter, Basic consummated its involvement in the Christmas Meadows prospect operated by Double Eagle Petroleum Company (Double Eagle). One of the more exciting, true wildcat projects in the Rocky Mountain region, Christmas Meadows is a “high risk – high reward” venture located in Summit County, Utah in the southwest corner of the prolific Green River Basin and along the Wyoming Overthrust Belt. Containing 41,000 gross acres, the Christmas Meadows prospect has a long history. Originally identified as a structural dome by Gulf Oil Company in the 1970s, the project has been pursued by numerous major oil companies; all to no avail due to federal permitting issues. With 22 years since its first fledgling involvement, Double Eagle (and its partners) now control the prospect and have been successful in resolving these federal permitting issues. The first well, the Table Top Unit #1, is expected to commence drilling operations in August 2006. Viewed by the Company as a “swing for the fences” opportunity, if successful, Basic’s 2% interest in the Christmas Meadows prospect could have a considerable impact on a company the size of Basic.

Company Developments

The following points summarize the Company’s capital investment activity during fiscal 2006:

U.S. Operations

Williston Basin, Horizontal Bakken Area

• Completion operations were finalized on the Halvorsen #31X-1 dual-lateral, horizontal well in Richland County, Montana. This well, which was drilled in the prior fiscal year, is currently producing approximately 200 barrels of oil, 40 barrels of water and 100 Mcf of gas per day. Basic has a 25.77% working interest in this well which is operated by Headington Oil, L.P.

• Basic drilled the Johnson #3-21H single-lateral, horizontal well in Richland County, Montana in the September 2005 quarter. The well is operated by Nance Petroleum Corporation, a subsidiary of St. Mary Land & Exploration. Initially producing 282 barrels of oil, 144 barrels of load water and 104 Mcf of gas per day, by December 2005 production had declined severely. In February 2006, downhole diagnostic pressure tests were performed to determine the cause of this abnormally steep production decline. The well is now back on production at rates lower than 50 barrels of oil per day while the results of the diagnostic tests are analyzed. However, based on preliminary results it appears unlikely

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that a second well will be drilled on this drilling unit. Basic has a 12.5% working interest in this well.

• In November 2005 the Company commenced drilling the Halvorsen #21X-36, a single-lateral, horizontal well in Richland County, Montana. The well was completed near the end of December and began producing in early-January 2006 at rates in excess of 300 barrels of oil per day. However, early flow rates were impeded by sand accumulations in the wellbore to the point that the well ceased to flow. Workover operations conducted in mid-March 2006 rectified this problem and the well is currently flowing an average of 235 barrels of oil per day. Basic has a 25.77% working interest in this well which is operated by Headington Oil, L.P.

Williston Basin, Banks Prospect

• In the June 2005 quarter, Basic acquired a 20% interest in 13,000 acres in its Banks prospect in McKenzie County, North Dakota. The majority of these leasehold rights are in the developing, though unproven, extension of the Bakken horizontal play into North Dakota.

• In the December 2005 quarter, Basic began drilling the State #16-1H, a horizontal Bakken well in McKenzie County, North Dakota. During completion operations in January, upon testing the un-stimulated Bakken formation, Basic, along with its partners, were not sufficiently encouraged by initial indicators to incur the cost of hydraulically stimulating the Bakken formation and deferred further evaluation by sealing off the formation behind a removable plug. Instead, Basic completed the State #16-1H in the Rival formation flowing at the rate of approximately 80 barrels of oil and 10 barrels of water per day. While to date the well remains un-stimulated, Basic expects to stimulate this zone in the near future in efforts to enhance production. Basic has a 20% working interest in this well which is operated by Missouri Basin Well Service, Inc.

• In the March 2006 quarter, the Company drilled and completed the LM #1, a 10,200 foot, vertical Rival test in McKenzie County, North Dakota. Initial swab rates were disappointing. However, at March 31 2006, the well remained unstimulated. Basic has nearly a 20% working interest in the well which is operated by Missouri Basin Well Service.

• Following the conclusion of drilling the LM #1, Basic, along with its partners, commenced drilling the LM #2, originally planned as a 10,200 foot, vertical Rival test. Upon reaching its planned depth, the lower portion of the well was cemented off and the well was drilled horizontally into the Rival formation. At March 31, 2006 the LM #2 was still drilling. The well is operated by Missouri Basin Well Service and Basic has nearly a 20% working interest.

Williston Basin, Indian Hill Field

• In December 2005 the Company began drilling the Lynn #3H in McKenzie County, North Dakota. This well, operated by Missouri Basin Well Service, targeted the Nisku formation with a single horizontal wellbore. Following completion in the March 2006 quarter, the well is averaging 15 barrels of oil and 130 barrels of water per day. Basic has a 17.13% working interest. Although producing, Basic considers this well unsuccessful and expects to recomplete this well into the Rival formation in the current fiscal year.

Williston Basin, Other Areas

• Kerr-McGee Rocky Mountain Corporation began drilling a horizontal well in the TR-Madison Unit in Billings County, North Dakota. Basic has a 1.07% working interest in the entire TR-Madison Unit.

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On-Shore Gulf Coast

• The Company drilled the Homer Lowe #1, a second “3-D Bright Spot” well in Wharton County, Texas. After encountering significant pressures and hydrocarbon inflows at 11,300 feet, cementing off the lower portion of the well, and incurring an additional $98,000 in costs, Basic elected to terminate its participation in the venture due to significant cost overruns. The Company had a 5% working interest in this well. The venture eventually resulted in a producing well after the expenditure of over $11,000,000 by the remaining partners.

• Following an unsuccessful attempt to restore production at 14,000 feet in its high-pressure, deep-gas PIDCO #2 well in Matagorda County, Texas, the Company successfully re-completed the well into a new producing horizon at 13,100 feet. The well was tested at a rate of 1.5 million cubic feet (MMcf) of natural gas and 210 barrels of condensate per day. However, the well encountered numerous surface equipment failures and/or was unable to treat impurities out of the natural gas at these high rates. Following numerous days of lost production, various pieces of production equipment were alternatively repaired or restored to original specifications. In addition, the well was down throughout February 2006 to replace the downhole tubing, but was successfully returned to production on March 1, 2006. As a result of these surface equipment repairs, the well did not incur any downtime during March 2006 and produced a total of 1,853 barrels of oil and 18.8 MMcf gas. Basic is the operator of the well and has a 12.77% working interest (9.09% net revenue interest).

• During fiscal 2006, the Turf Grass #1, a successful Yequa “3-D Bright Spot” well in Wharton County, Texas drilled in fiscal 2005 continued to decline. In the September 2005 quarter, efforts to install gas lift equipment to maintain production on the well were only marginally successful due to increasing water production. And by December 2005, water production increased to a point that the well ceased to flow. In the March 2006 quarter production was restored by using the gas from an offset well to power the Turf Grass’s gas lift system The well is currently on production and has stabilized at a rate of 90 Mcf and 20 barrels of oil per day. Basic has a 5% working interest in the well which is operated by PetroReal, Inc.

• The Company participated in the re-entry of a temporarily abandoned, 14,000 foot Discorbis formation well in St. Mary Parish, Louisiana. Initial re-entry efforts were hampered by equipment that was abandoned in the well by prior owners. However, during the March 2006 quarter, sufficient progress and preliminary testing indicated rates that justified the installation of production equipment, in addition to gas metering and sales facilities. At year-end, the well was shut-in while this installation occurred. Basic has a 10% working interest in this well that is operated by MTBB Acquisition Company, LLC.

Canadian Operations

• Legent Resources Corporation, Basic’s wholly-owned Canadian subsidiary, wrote off its remaining Canadian full cost pool assets and disclosed that it has no plans to lease additional acreage or to conduct any further Canadian operations.

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Subsequent Events

Williston Basin, Banks Prospect

• In early May 2006, the LM #1 in McKenzie County, North Dakota was shut-in following a hydraulic stimulation that was commercially unsuccessful. The Company has a number of options with this well and the spacing unit it occupies, and intends to analyze the results of the LM #2 prior to undertaking further efforts on the LM #1. As of this date this situation remains unchanged. Basic has a 20% working interest in this well.

• The LM #2 in McKenzie County, North Dakota was initially flowing rates of 147 barrels of oil and 107 barrels of water a day from an un-stimulated Rival formation. On June 13, 2006, following the decline to less then 90 barrels of oil a day, the Company installed a pumping unit. Rates of approximately 120 barrels of oil and 140 barrels of water per day have been recorded. However, the Company cautions that these unstimulated pumping rates are very preliminary and may be influenced either positively or negatively by various factors including future stimulation efforts, downhole pump efficiencies, wellbore inflow rates, unknown wellbore obstructions and/or other factors not currently known. Confirming this observation, diagnostic tests conducted one week later, indicate that the existing artifical lift equipment is not removing all of the available fluids from the wellbore suggesting that the well could produce at higher rates.

• The State #16-1H in McKenzie County, North Dakota continues to flow at approximately 55 barrels of oil per day. The well currently remains un-stimulated in the Rival formation.

On-Shore Gulf Coast

• In Louisiana, following a successful re-entry, the Discorbis B1 RB SUB: Martin 1-D was placed on production in mid-April. The well is currently flowing at a rate of 1.6 MMcf of gas and 6 barrels of condensate per day.

Contemplated Activities

In addition to the discussion in Areas Of Focus and Subsequent Events described above, the Company anticipates pursuing the following activities in fiscal 2007 (year ending March 31, 2007).

Other Areas

On its Antenna Federal property in Weld County, Colorado, Basic has previously disclosed the receipt of proposals from its partner to deepen three additional Codell formation wells to the J-Sand formation. These efforts have never been undertaken due to various issues concerning Basic’s partner on the property and Bureau of Land Management permitting requirements, both of which are beyond the control of the Company. It is Basic’s understanding that one of these three wells has now been approved. As a result, the Company expects to deepen at least one of these wells in the current fiscal year. Basic estimates the cost to deepen one well to be $150,000.

Basic has received notification from its partner, Double Eagle Petroleum Co., that it has a drilling rig under contract and expects to commence drilling operations on the Table Top Unit #1, the initial Christmas Meadows prospect well, in early-August 2006. Basic has a 2% working interest in this well and has spent $17,000 to-date on land costs and $52,000 on road and location costs. Basic anticipates spending an additional $200,000 in drilling costs.

Basic is continually evaluating other drilling and acquisition opportunities for possible participation. Typically, at

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any one time, several opportunities are in various stages of due diligence. The Company’s 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. Basic cautions that the absence of news and/or press releases should not be interpreted as a lack of development or activity.

The Company 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 the Company is not able to anticipate.

Segment Information and Major Customers

Industry segment. The Company is engaged only in the upstream segment of the oil and gas industry, which comprises exploration, production, operations and development. The Company has no gathering, transportation, refining or marketing functions.

Markets. The Company’s oil and natural gas is sold to various purchasers in the geographic area of its properties. Basic is a small company and, as such, has no impact on the market for its 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 the control of Basic.

During fiscal 2006, Basic sold 57% of its oil and gas production to three purchasers: Murphy Oil USA, Inc. (25%), Valero Marketing & Supply Co. (17%), and Plains Marketing LP (15%). Sales to no other customer of Basic (or group of customers under common control) were equal to 10 percent or more of oil and gas sales. Since there is strong competition among purchasers, management does not believe it is dependent on any one purchaser or group of purchasers. See also Note 8 to the Consolidated Financial Statements.

Competition

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

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

Regulations

General. The operations of the Company 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. The Company is further affected by changes in such laws and by constantly changing administrative regulations. To the best of its knowledge, the Company is in compliance with all such

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regulations and is not aware of any claims that could have a material impact upon the Company’s financial condition, results of operations, or cash flows.

Environmental matters. The Company is subject to various federal, state, regional and local laws and regulations relating 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 Basic utilizes are owned and operated by third parties whose disposal practices are outside of the Company’s control. With respect to the three disposal wells that Basic owns and operates, it currently uses 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 Basic any differently than other companies in this industry who operate in a given geographic area. The Company is not aware of any environmental claims which could have a material impact upon the Company’s 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, Basic has not had to hire any new employees to comply with these regulations. The Company will continue to make expenditures in its efforts to comply with these requirements, which are unavoidable business costs in the oil and gas industry.

Although the Company is not fully insured against all environmental and other risks, it maintains insurance coverage that it believes is customary in the industry.

Risk Factors

Volatility of oil and gas prices. The Company’s revenues, operating results, profitability, future rate of growth and the carrying value of its 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 the control of the Company 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 the Company’s financial condition and results of operations. Such decline would reduce the Company’s cash flow and borrowing capacity and both the value and the amount of the Company’s existing oil and gas reserves.

The Company believes that substantially all of its domestic oil that is produced can be readily sold at prevailing market prices. In prior years the oil prices Basic received were typically $2.25 to $2.50 lower than the benchmark U.S. crude spot price because of adjustments for location and grade. In January 2006 this price differential began to widen to $6 to $7 per barrel for production from the northern portion of the Williston basin. Differentials for both Wyoming production and production from the southern portion of the Williston basin increased to as much as $30 per barrel for March 2006 production. There are several factors leading to this

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increased price differential. Due to more and more successful drilling projects in the Williston basin there has been an increase in production in the area as well as a surge in the amount of Canadian barrels coming across the border. This has led to an overload for the pipelines in the area and the situation is further compounded by limited refinery capacity and reduced refinery intake during times of equipment repair and facility upgrades.

The Company had only five marginal and low volume wells that were exposed to the highest differentials. For May 2006 the northern Williston differential was in the $9 per barrel range while the Wyoming and south Williston spread had contracted to the $15 range.

Substantially all of Basic’s gas production is sold at prevailing wellhead gas prices, subject to additional charges customary to an area. Basic does not own or operate any gas gathering or processing plant facilities nor does it possess sufficient volume on any pipeline to market its 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 the Company’s control. The reserve information set forth in this Form 10-KSB (see Note 13 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 the Company’s reserves will likely vary from estimates, and such variances may be material.

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 the Company’s 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. The future success of Basic is highly dependent on the Company’s ability to find, develop and/or acquire additional oil and gas reserves that are economically recoverable. Without continued

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successful exploitation, exploration or acquisition projects, the Company’s 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 to the Company. In addition, the Company may be liable for environmental damage caused by previous owners of properties purchased or leased by the Company. 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 Basic is not fully insured against all environmental and other risks, it maintains insurance coverage which it believes 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 the Company’s properties in Montana and North Dakota, severe weather conditions, especially in the winter months, could have a material adverse effect on Basic’s operations and cash flow.

At March 31, 2006 the Company had eight full-time employees: four 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, Basic at times hires up to five contract technical/professional personnel in its 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 the Company’s financial position and liquidity, the amount of and its ability to make debt service payments should it utilize some or all of its available borrowing capacity, its strategies, either existing or anticipated, financial instruments, and other matters, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations are disclosed in this Form 10-KSB in conjunction with the forward-looking statements included in this Form 10-KSB.

The Company’s intentions and expectations described in this Form 10-KSB with respect to possible exploration and development activities concerning properties in which it holds interests may be deemed to be forward-looking statements. These statements are made based on management’s 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 the Company’s relative interest in the property and its estimate of its 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

12

revisions to management’s expectations and intentions and, thus, the Company may alter its plans regarding these exploration and development activities. Furthermore, circumstances beyond the Company’s 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, 2006 Basic owned a working interest in 77 producing oil wells and 9 producing gas wells. The Company currently operates 51 of these wells in five states: North Dakota, Montana, Colorado, Texas and Wyoming. These operated wells contributed approximately 54% of Basic’s total liquid hydrocarbon sales and approximately 69% of total natural gas sales in fiscal 2006. A significant portion of the Company’s production is encumbered and used to secure bank debt.

Producing Property

	Gross Wells				Net Wells
	Oil		Gas		Oil		Gas
Colorado		—		7		—		4.20
Louisiana		1		—		0.01		—
Montana		18		—		9.65		—
North Dakota		36		—		8.63		—
Texas		21		2		18.75		0.18
Wyoming		1		—		0.47		—
Total		77		9		37.51		4.38

Production

Specific production data relative to the Company’s 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, 2006 the discounted present value of Basic’s estimated proved developed oil and gas reserves, net of deferred income taxes, was $15,032,000, a 1% increase over the prior year’s estimated proved developed oil and gas reserves of $14,819,000. The timing of the Company’s drilling program during fiscal 2006 was the most significant factor that contributed to the limited increase in Basic’s reserves from 2005 to 2006. In terms of capital expenditures, over 75% of the dollars spent in fiscal 2006 were related to projects undertaken during the third and fourth quarters of the year. As a result, at year end, not only did the Company have a number of wells in various stages of drilling and/or completion for which no reserves were added, even some new wells that were on production had not established a sufficient production history to allow a

13

reasonable estimate of potential contribution to the Company’s reserve base at March 31, 2006. Further discussion of Basic’s estimated oil and gas reserves can be found in Note 13 to the Consolidated Financial Statements.

Geographically, the Company’s 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, 2006:

	Net Oil		Net Gas
	(Bbls)		(Mcf)		BOE		%
Williston Basin
Operated		312,000		87,000		327,000		23.4
Non-Operated		255,000		186,000		286,000		33.4
		567,000		273,000		613,000		56.8
South Texas
Operated		365,000		51,000		374,000		29.7
Non-Operated		1,000		2,000		1,000		0.1
		366,000		53,000		375,000		29.8
D-J Basin
Operated		13,000		629,000		118,000		12.6
Non-Operated		2,000		15,000		4,000		0.7
		15,000		644,000		122,000		13.3
Other Areas
Operated		4,000		—		4,000		0.1
Non-Operated		—		—		—		—
		4,000		—		4,000		0.1
Total		952,000		970,000		1,114,000		100.0

Leasehold Acreage

The Company leases 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.” Basic’s acreage is comprised of developed and undeveloped acreage. Typically, undeveloped acreage is considered an indication of the Company’s “raw material” and, therefore, its potential to replace reserves in the future. From the mid-1990s through fiscal 2001 Basic’s strategy had been the acquisition and exploitation of producing properties. Given this strategy, there was no need for Basic to amass undeveloped acreage blocks. As a result, Basic has had a minimal amount of undeveloped acreage relative to other exploration companies. As the Company has shifted to a growth

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strategy that is more focused on adding reserves through exploration and development drilling, it has begun to acquire various leasehold interests. To-date, Basic’s largest acreage acquisition has been a 20% interest in 13,000 gross acres in the Banks prospect in McKenzie County, North Dakota.

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Colorado		640		384		—		—
Louisiana		687		52		—		—
Montana		6,291		3,069		4,503		1,930
North Dakota		15,073		2,812		24,665		4,240
Texas		3,080		2,486		—		—
Utah		—		—		41,397		719
Wyoming		714		273		920		476
Total		26,485		9,076		71,485		7,365

Field Service Equipment

At March 31, 2006 one of the Company’s 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, three pickup trucks and various ancillary service vehicles. None of the vehicles are encumbered.

Office Lease

The Company currently leases approximately 2,300 square feet of office space in downtown Denver, Colorado from an independent third party for $3,000 per month. The lease term is for a five-year period ending February 28, 2008. For additional information see Note 6 to the Consolidated Financial Statements.

ITEM 3
LEGAL PROCEEDINGS

None.

ITEM 4
SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS

No matter was submitted to a vote of Basic’s shareholders during the fourth quarter ended March 31, 2006.

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Part II

ITEM 5
MARKET FOR COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS

Basic’s 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. Prices are obtained from Pink Sheets LLC.

	High		Low
Year Ended March 31, 2005
First Quarter	$	0.60	$	0.35
Second Quarter		0.68		0.40
Third Quarter		0.73		0.57
Fourth Quarter		2.86		0.65
Year Ended March 31, 2006
First Quarter	$	1.98	$	1.13
Second Quarter		2.65		1.60
Third Quarter		3.37		1.88
Fourth Quarter		2.73		2.06

The closing bid price on June 21, 2006 was $2.06. 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 June 21, 2006, Basic had approximately 2,160 shareholders of record. Basic has 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. The Company’s 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

The Company’s 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 the Company’s 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, management believes the cash generated from operations will provide sufficient working capital for the Company to meet its existing and normal recurring obligations as they become due in fiscal 2007. In addition, as mentioned in the “Debt” section below, Basic has an available borrowing capacity of $4,000,000 as of June 21, 2006.

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Capital Structure and Liquidity

Financing. The Company recognizes the importance of developing its capital resource base in order to pursue its objectives. However, subsequent to its last public offering in 1980, debt financing has been the sole source of external funding.

Bank Debt. The Company’s current banking relationship, established in March 2002, is with American National Bank (the Bank), located in Denver, Colorado. Effective January 3, 2006 Basic and the Bank 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. Also, the maturity date of the loan was extended for one year to December 31, 2007. The interest rate at March 31, 2006 is the prime rate plus 0.25% compared to prime plus 2% at March 31, 2005. Basic’s effective annual interest rate was 8.00% and 7.75% at March 31, 2006 and 2005, respectively. See Note 5 to the Consolidated Financial Statements for a more detailed discussion of the Company’s bank credit facility.

During both the years ended March 31, 2006 (2006) and March 31, 2005 (2005) Basic utilized its credit facility to fund portions of its drilling program and incurred interest charges of $7,000 and $1,000, respectively. On June 21, 2006 the Company had no outstanding principal balance on the line of credit with the entire $4,000,000 available for borrowing. If necessary, Basic may borrow funds to reduce payables, finance recompletion or drilling efforts, fund property acquisitions, or pursue other opportunities the Company cannot envision at this time.

Hedging. The Company periodically uses hedging techniques to limit its exposure to oil price fluctuations. Typically Basic will utilize either futures or option contracts. During 2006 and 2005 the Company did not participate in any hedging activities. The Company had no open futures or option contracts in place at either March 31, 2006 or March 31, 2005. Additional information concerning the Company’s hedging activities appears in Note 1 to the Consolidated Financial Statements.

Working Capital. At March 31, 2006 the Company had a working capital surplus of $217,000 (a current ratio of 1.15:1) compared to a working capital surplus at March 31, 2005 of $574,000 (a current ratio of 1.38:1). Current assets declined $388,000 (19%) while current liabilities decreased $31,000 (2%). Current assets were primarily affected by the cash requirements needed to fund Basic’s expanded drilling program in 2006.

Cash Flow. As mentioned above, the Company’s primary source of funding is the cash flow from its operations. Cash provided by operating activities rose 17% from $2,576,000 in 2005 to $3,013,000 in 2006. This increase was primarily due to a combination of improved oil production and higher commodity prices.

Net cash used in investing activities increased 102% from $2,117,000 in 2005 to $4,281,000 in 2006. This increase reflects Basic’s commitment to its aggressive drilling program and underscores the Company’s emphasis on growth through exploratory and development drilling given the current pricing environment and the opportunities presented to the Company.

As the Company’s drilling and completion activity accelerated during the third and fourth quarters of 2006 Basic utilized debt financing to fund a portion of its short-term working capital needs. At March 31, 2006 the outstanding principal balance on its line of credit was $445,000. By June 21, 2006 this outstanding balance had been reduced to zero.

Capital Expenditures. The Company’s exploration and development projects in 2006 were primarily focused in two specific areas: the Montana and North Dakota portions of the Williston basin and onshore areas along the Gulf Coast. In the Williston basin the Company’s efforts were concentrated in three areas: Richland County, Montana and its prolific Bakken formation, the Indian Hill Field in McKenzie County, North Dakota and the Banks prospect also located in McKenzie County, North Dakota. Total capital expenditures during

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2006 for oil and gas property and equipment and various leasehold interests were $4,275,000. Ninety-seven percent of these costs can be broken down between the specific areas of focus as follows:

• Horizontal Bakken – Richland County, Montana. The Company invested $1,368,000 in three wells in this area: $137,000 in additional completion costs on one well that was drilled and placed on production in 2005 and $1,231,000 on two other wells, both of which were on production at March 31, 2006.

• Indian Hill Field – McKenzie County, North Dakota. A total of $484,000 was invested in this area: $18,000 to purchase additional leasehold interests; $13,000 in additional completion costs on a well that was drilled in 2005; and $453,000 to drill and complete the Company’s third well in this field.

• Banks Prospect – McKenzie County, North Dakota. Basic spent a total of $1,707,000 on this prospect: $348,000 for acreage acquisition and $1,359,000 on three wells, one of which was producing at March 31, 2006 and the other two in various stages of drilling and completion.

• Onshore Gulf Coast. The Company invested $532,000 in three ventures: $207,000 for a leasehold interest and re-entry costs in a gas well in St. Mary Parish, Louisiana; $290,000 for a well in Wharton County, Texas in which Basic terminated its participation due to ongoing cost overruns by the operator; and $35,000 to re-complete the lower Frio formation in its PIDCO #2 gas well in Matagorda County, Texas.

• Other Areas – Summit County, Utah. Through March 31, 2006 Basic had invested $69,000 in a deep gas test in the southwest corner of the Green River Basin and along the Wyoming Overthrust Belt. Of this amount, $17,000 was applicable to the Company’s leasehold interest and $52,000 was spent on initial location costs.

These projects were funded with a combination of internally generated cash flow from operations and short-term debt financing. See also the Areas of Focus and Company Developments sections of Part 1 of this report for further discussion related to Basic’s exploration and development activities.

These capital expenditures are fundamental to the component of the Company’s growth strategy that focuses on increasing its oil and gas reserves. As is the case with most of the projects listed above, drilling and completion projects in the oil and gas industry will span a period of time such that the results of these projects undertaken during any one particular year may not be reflected in oil and gas reserve estimates until subsequent periods. This is particularly true if a number of projects are started late in the year as was the case for Basic in 2006. Of the $4,275,000 of costs incurred during 2006, approximately $3,277,000 was related to projects undertaken during the third and fourth quarters of the year. As such, at year end Basic had a number of projects in various stages of drilling and/or completion for which enough data was not available to properly evaluate and add to the Company’s reserve base at March 31, 2006. Of this $4,275,000, approximately two-thirds, or $2,850,000 relates to properties that have not yet been evaluated for purposes of estimating and adding reserves, and therefore, the results of which are not reflected in the various analysis and tables presented in Note 13 to the Consolidated Financial Statements.

Basic is continually evaluating exploration and development opportunities in an effort to grow its oil and gas reserves. At present cash flow levels and available borrowing capacity, Basic expects to have sufficient funds available for its share of any additional acreage, seismic and/or drilling cost requirements that might arise from these opportunities. However, the Company 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

18

other events which the Company is not able to anticipate.

Divestitures/Abandonments. The Company has previously disclosed that it holds a number of marginal, operated and non-operated properties that provide minimal impact to the Company’s operations. Basic will continue to produce these properties as long as they remain profitable and, while not actively attempting to sell these properties, will entertain any reasonable purchase offers.

Other. The Company recorded a valuation allowance of $359,000 at March 31, 2006 equal to the excess of deferred tax assets over deferred tax liabilities. This valuation allowance reflects the Company’s belief that the benefits from the deferred tax assets will more than likely not be realized. See Note 9 to the Consolidated Financial Statements.

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.

Capital Resources

Overview. In addition to the Company’s routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, the Company requires capital to fund its exploratory and development drilling efforts, and the acquisition of additional properties as well as any development and enhancement of these acquired properties. Even though Basic’s borrowing base was increased from $1,000,000 to $4,000,000 in 2006, relative to its recent capital expenditures, the Company’s current credit facility is somewhat limited. In addition, the Company is reluctant to use debt to fund true exploration efforts. Concurrently, the Company has received numerous inquiries regarding the possibility of funding the Company’s efforts through equity contributions or debt instruments. Given strong cash flows and the relatively modest nature of the Company’s current drilling projects (one or two well exposure), management has thus far declined these overtures. Management’s primary concern in this area is the dilution of its existing shareholders. However, going forward, given that one of the key components of Basic’s growth strategy is to expand its oil and gas reserve base through exploration and development drilling, if the Company were presented with a significant opportunity and available cash and bank debt financing were insufficient, it is possible Basic would consider alternative forms of additional financing.

Other Commitments. The Company has no obligations to purchase additional, or sell any existing, oil and gas property. Basic also does not have any other commitments beyond its office lease and software maintenance contracts (see Note 6 to the Consolidated Financial Statements).

Results of Operations

Fiscal 2006 Compared with Fiscal 2005

Overview. Net income for the year ended March 31, 2006 (2006) was $2,815,000 compared to net income of $1,845,000 for the year ended March 31, 2005 (2005), a 53% increase.

Revenues. Oil and gas sales revenue increased $1,768,000 (37%) in 2006 over 2005 as a result of both an increase in volume sales and higher commodity prices. Oil sales revenue alone increased $1,596,000 (41%). An increase in sales volumes in 2006 contributed $356,000 while higher oil prices in 2006 added $1,240,000. Gas sales revenue alone increased $172,000 (19%) in 2006 over 2005. A positive variance of $297,000 from higher natural gas prices was reduced by a $125,000 negative variance attributable to lower natural gas sales volumes.

Volumes and Prices. Total oil sales volume increased 9% from 91,600 barrels in 2005 to 99,900 barrels

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in 2006 while the average price per barrel jumped 29% from $42.94 in 2005 to $55.35 in 2006. Total gas sales volume decreased 14% from 163.7 million cubic feet in (MMcf) 2005 to 140.8 MMcf in 2006 while the average price per Mcf rose 39%, from $5.45 in 2005 to $7.56 in 2006. The increase in oil sales volumes was primarily due to incremental sales of 19,200 barrels from five new Williston basin wells that were placed on production in either late-2005 or 2006. Partially offsetting this new production was normal production decline. With respect to gas sales volumes, 8.8 MMcf of incremental gas production from four of the five new Williston basin wells in 2006 was more than offset by a drop of 33.3 MMcf of gas sales from the Company’s natural gas wells in Weld County, Colorado. On an equivalent barrel (BOE) basis, sales increased 4% from 118,900 BOE in 2005 to 123,400 BOE in 2006.

Expenses. Oil and gas production expense increased $582,000 (38%) in 2006 over 2005. 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 $142,000 (12%) from $1,200,000 in 2005 to $1,342,000 in 2006. Workover expense rose $440,000 (137%) from $322,000 in 2005 to $762,000 in 2006. On an equivalent barrel basis, routine lease operating expense increased 8% from $10.10 per BOE in 2005 to $10.88 in 2006 while workover expense climbed 128% from $2.71 in 2005 to $6.18 per BOE in 2006.

The five new Williston basin wells added $31,000 to routine lease operating expense in 2006. Also, in general, Basic is experiencing an industry-wide cost increase from service companies that is indicative of the strong demand for general oilfield services within Basic’s core operating areas, particularly in the Williston basin in eastern Montana and western North Dakota. This strong demand is a reflection of the historically high level of oil prices that have benefited both the producers and service companies.

In addition, during 2006 the Company experienced an unusually high number of workovers, both in quantity and magnitude, the most notable of which were workovers on the PIDCO #2, the Harold H. Haugen #25-1 and the Lundblad #1 salt water disposal well. Together these three workovers accounted for $358,000, or 81%, of the increase in workover expense in 2006 over 2005. Basic spent $160,000 in an unsuccessful attempt to clean out the PIDCO #2 and re-establish production from the previously producing Frio formation. Since abandoning that workover, Basic has since come up-hole and successfully completed another horizon. In July 2005 the Haugen well in Divide County, North Dakota developed a casing leak and Basic was forced to spend $113,000 on repairs that were successful. In September 2005 Basic began an extensive operation on its Lundblad salt water disposal well in McCone County, Montana. The Company spent $85,000 to clean out scale and debris that had been slowly building over the years and obstructing the perforations to the point that injection pressures had increased significantly. Basic was able to successfully clean out the well and even “shoot” additional perforations that should lower injection pressure rates such that Basic should see a measurable reduction in its electricity costs at the disposal facility and a corresponding reduction in lifting costs on the three producing wells that utilize the Lundblad disposal well. Excluding the $358,000 applicable to these three wells, workover expense was $404,000 in 2006 compared to $322,000 in 2005, an increase of 25%, and total oil and gas production expense was $1,746,000 in 2006 compared to $1,522,000 in 2005, an increase of 15%. Again excluding these three wells, workover expense per BOE would have increased 19% from the $2.71 in 2005 to $3.28 per BOE in 2006.

Primarily as a result of the increase in oil and gas sales revenue, production taxes, which are a function of sales revenue, increased $63,000 (16%) in 2006 over 2005. Production taxes as a percent of oil and gas sales revenue actually declined from 8.2% in 2005 to 7.0% in 2006. This percentage drop can be attributed

20

to a less than 1 percent tax rate on Basic’s two new horizontal wells in Montana, the Halvorsen 31X-1 and the Halvorsen 21X-36. Montana tax regulations allow for a significant tax incentive during the first two years of production after new wells are drilled and completed.

The overall lifting cost (oil and gas production expense plus production taxes) per BOE was $20.78 in 2006 compared to $16.14 in 2005. Again, excluding the effect of the three workovers above, the lifting cost per BOE would have risen 11% to $17.89 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 $47,000 (9%) in 2006 over 2005. Included in the 2006 expense is an $85,000 ceiling limitation impairment charge applicable to the Company’s Canadian operations while 2005 includes a similar $240,000 charge. With respect to U.S. operations only, depreciation and depletion expense increased $200,000 (78%) in 2006 over 2005 due to a significant increase in the full cost pool depletable base resulting from the Company’s recent extensive drilling activity. For U.S. operations only, depreciation and depletion expense per BOE increased from $2.15 in 2005 to $3.70 in 2006.

Accretion of asset retirement obligation increased $4,000 (6%) in 2006 over 2005. This increase is a result of revisions to previous estimates of future plugging and abandonment costs that were made at the time SFAS No. 143 was adopted in the first quarter of fiscal 2004. Additional information concerning SFAS No. 143 and related activity during 2006 can be found in Note 2 to the Consolidated Financial Statements.

Gross general and administrative (G&A) expense increased $126,000 (20%) while net G&A expense increased $108,000 (26%) in 2006 over 2005. Gross G&A expense differs from net G&A expense in that the Company is allowed to recover an overhead fee on wells that it operates. This fee is applied against, and serves to reduce, gross G&A expense. Approximately $16,000 of the increase in G&A in 2006 is directly related to a unique opportunity the Company had in April 2005 with respect to a proposal involving a strategic acquisition. After considerable due diligence, management elected not to proceed with the acquisition over concerns about operational synergy and shareholder dilution. Also contributing to the increase in G&A in 2006 were increases in employee benefits, SEC reporting and audit related costs, and the design and launch of the Company’s new website. The percentage of gross G&A expense that the Company was able to charge out was 30% in 2006 compared to 33% in 2005. Net G&A expense per BOE increased 51% from $3.50 in 2005 to $4.24 in 2006. However, net G&A expense as a percentage of total sales revenue dropped from 8.6% in 2005 to 7.9% in 2006.

Other Income/Expense. Due to significantly higher cash balances throughout the first two quarters of 2006 compared to 2005, interest and other income, which consists almost entirely of interest income, increased from $5,000 in 2005 to $23,000 in 2006. Interest and other expenses, which consists primarily of interest from short-term debt financing, increased from $1,000 in 2005 to $11,000 in 2006 as the Company accelerated its drilling program during the second half of 2006.

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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.

	2006		2005		2004
Production:
Oil (barrels)		99,900		91,600		83,100
Gas (Mcf)		140,800		163,700		114,500
Revenue: (in thousands)
Oil	$	5,530	$	3,934	$	2,458
Gas		1,065		893		514
Total		6,595		4,827		2,972
Less: Total production expense (in thousands)1		2,564		1,919		1,523
Gross profit (in thousands)	$	4,031	$	2,908	$	1,449
Depletion expense (in thousands)4	$	456	$	256	$	224
General and administrative expense (in thousands)	$	524	$	416	$	286
Average sales price2
Oil (per barrel)	$	55.35	$	42.94	$	29.58
Gas (per Mcf)		7.56		5.45		4.49
Average production expense1,2,3		20.78		16.14		14.90
Average gross profit2,3		32.66		24.45		14.18
Average depletion expense2,3,4		3.70		2.15		2.19
Average general and administrative expense2,3		4.24		3.50		2.80

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 Company management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Management bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, management believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts. The Company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and gas property, the accounting for oil and gas reserves, the estimate of its asset retirement obligations, and the estimate of the valuation allowance with respect to its deferred tax asset.

Oil and Gas Property. Basic utilizes the full cost method of accounting for costs related to its 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

22

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, Basic will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and results in lower depreciation and depletion in future periods. The write-down may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.

Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the Company’s 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 Basic’s 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 Basic’s reported oil and gas reserves at March 31, 2006 are based on estimates prepared by an independent petroleum engineering firm. The remaining seven percent of the Company’s oil and gas reserves were prepared in-house. See also Note 12 to the Consolidated Financial Statements.

Asset Retirement Obligations. The Company has significant obligations related to the plugging and abandonment of its 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 Basic 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. The Company reviews the estimate of its 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 2 to the Consolidated Financial Statements.

Deferred Taxes. Deferred income taxes have been determined in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” At March 31, 2006 Basic recorded a valuation allowance of $359,000 as it was unable to determine that the excess of deferred tax assets over deferred tax liabilities is more likely than not to be realized. This estimate of the valuation allowance is periodically re- evaluated by the Company. If Basic continues to be profitable, it is possible a portion, or all, of the Company’s deferred tax asset may be recorded as an asset on the Balance Sheet. See also Note 9 to the Consolidated Financial Statements.

Off Balance Sheet Transactions, Arrangements or Obligations

The Company has no off balance sheet transactions, arrangements or obligations.

Recent Accounting Pronouncements

In December 2004 the FASB issued Statement of Financial Accounting Standards No. 123(R), (SFAS 123(R)), “Share-Based Payment,” a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) supersedes APB Opinion 25, “Accounting for Stock Issued to Employees” and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows.” SFAS 123(R) requires a company to recognize equity-based compensation, including stock option grants, at

23

fair value in the income statement, and discontinues accounting for equity-based compensation under APB Opinion 25, the intrinsic value method. SFAS 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as cash flow from financing activities rather than as cash flow from operations, as required currently. The requirements of this pronouncement are effective for fiscal periods beginning after June 15, 2005. The Company plans to adopt SFAS 123(R) in its June 30, 2006 quarter, the first quarter of its year ending March 31, 2007.

In prior years, as permitted by SFAS 123, Basic accounted for equity-based compensation using APB Opinion 25 and, as such, reported such equity-based compensation on a pro forma basis only. The impact of adoption of SFAS 123(R) cannot be predicted at this time because it will depend on levels of equity-based compensation, if any, to be granted in the future. However, had SFAS 123(R) been applied to prior periods, the impact of this accounting standard would have approximated the effect of SFAS 123 as described in the disclosure of pro forma net income and earnings per share in prior periods.

(Intentionally left blank.)

24

Basic Earth Science Systems, Inc.

Table of Contents

Consolidated Financial Statements
and Accompanying Notes

March 31, 2006 and 2005

	Page
Report of Independent Registered Public Accounting Firm – Hein & Associates LLP		26
Consolidated Balance Sheets		27 - 28
Consolidated Statements of Operations		29
Consolidated Statements of Shareholders’ Equity		30
Consolidated Statements of Cash Flows		31
Notes to Consolidated Financial Statements		32 - 43

25

ITEM 7
FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
Basic Earth Science Systems, Inc.
Denver, Colorado

We have audited the consolidated balance sheets of Basic Earth Science Systems, Inc. and subsidiaries as of March 31, 2006 and 2005, and the related consolidated statements of income, shareholders’ equity and cash flows for 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 provide 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, 2006 and 2005, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

HEIN & ASSOCIATES LLP

Denver, Colorado
June 9, 2006

26

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31,
	2006			2005
Assets
Current assets:
Cash and cash equivalents	$	78,000		$	892,000
Accounts receivable:
Oil and gas sales		913,000			796,000
Joint interest and other receivables		472,000			281,000
Allowance for doubtful accounts		(70,000	)		(70,000	)
Other current assets		297,000			179,000
Total current assets		1,690,000			2,078,000
Property and equipment:
Oil and gas properties (full cost method)		27,138,000			22,853,000
Furniture, fixtures and support equipment		368,000			372,000
		27,506,000			23,225,000
Accumulated depreciation		(314,000	)		(309,000	)
Accumulated depreciation and depletion – Full cost pool		(17,250,000	)		(16,794,000	)
Net property and equipment		9,942,000			6,122,000
Other non-current assets		218,000			215,000
Total non-current assets		10,160,000			6,337,000
Total assets	$	11,850,000		$	8,415,000

See accompanying notes to consolidated financial statements.

27

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets

	At March 31,
	2006			2005
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	389,000		$	406,000
Accrued liabilities		1,084,000			1,098,000
Total current liabilities		1,473,000			1,504,000
Long-term liabilities:
Long-term debt		445,000			—
Asset retirement obligation		1,372,000			1,175,000
Total long-term liabilities		1,817,000			1,175,000
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 at March 31, 2006 and 17,004,752 at March 31, 2005		17,000			17,000
Additional paid-in capital		22,710,000			22,701,000
Treasury stock (349,265 shares at March 31, 2005 and 2004); at cost		(23,000	)		(23,000	)
Accumulated deficit		(14,144,000	)		(16,959,000	)
Total shareholders’ equity		8,560,000			5,736,000
Total liabilities and shareholders’ equity	$	11,850,000		$	8,415,000

See accompanying notes to consolidated financial statements.

28

Basic Earth Science Systems, Inc.

Consolidated Statements of Operations

	Years Ended March 31,
	2006			2005
Revenues:
Oil and gas sales	$	6,595,000		$	4,827,000
Well service revenue		20,000			29,000
Total revenues		6,615,000			4,856,000
Expenses:
Oil and gas production		2,104,000			1,522,000
Production tax		460,000			397,000
Well servicing expenses		24,000			31,000
Depreciation, depletion and impairment		550,000			503,000
Accretion of asset retirement obligation		74,000			70,000
Asset retirement expense		63,000			76,000
General and administrative		524,000			416,000
Total expenses		3,799,000			3,015,000
Income from operations		2,816,000			1,841,000
Other Income (Expense):
Interest and other income		23,000			5,000
Interest and other expenses		(11,000	)		(1,000	)
Total other income		12,000			4,000
Income before income taxes		2,828,000			1,845,000
Income tax expense		13,000			—
Net income	$	2,815,000		$	1,845,000
Per share amounts:
Basic	$	0.168		$	0.111
Diluted	$	0.164		$	0.108
Weighted average common shares outstanding:
Basic		16,732,611			16,586,309
Diluted		17,125,635			17,054,290

See accompanying notes to consolidated financial statements.

29

Basic Earth Science Systems, Inc.

Consolidated Statements of Shareholders’ Equity

Years Ended March 31, 2006 and 2005

					Additional
	Common stock				paid-in		Treasury stock						Accumulated
	Shares		Par value		capital		Shares			Amount			deficit
Balance, April 1, 2004		16,879,752	$	17,000	$	22,692,000		(349,265	)	$	(23,000	)	$	(18,804,000	)
Stock options exercised		125,000		—		9,000		—			—			—
Net income		—		—		—		—			—			1,845,000
Balance, March 31, 2005		17,004,752		17,000		22,701,000		(349,265	)		(23,000	)		(16,959,000	)
Stock options exercised		125,000		—		9,000		—			—			—
Net income		—		—		—		—			—			2,815,000
Balance, March 31, 2006		17,129,752	$	17,000	$	22,710,000		(349,265	)	$	(23,000	)	$	(14,144,000	)

See accompanying notes to consolidated financial statements.

30

Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows

	Years Ended March 31,
	2006			2005
Increase (decrease) in cash and cash equivalents:
Cash flows from operating activities:
Net income	$	2,815,000		$	1,845,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		550,000			503,000
Accretion of asset retirement obligation		74,000			70,000
Change in:
Net accounts receivable		(308,000	)		(381,000	)
Other assets		(86,000	)		1,000
Accounts payable and accrued liabilities		(33,000	)		538,000
Asset retirement obligation		(6,000	)		(6,000	)
Other		7,000			6,000
Net cash provided by operating activities		3,013,000			2,576,000
Cash flows from investing activities:
Capital expenditures:
Oil and gas property		(4,271,000	)		(2,327,000	)
Support equipment		(8,000	)		(41,000	)
Purchase of lease and well equipment inventory		(45,000	)		(18,000	)
Proceeds from sale of oil and gas property and equipment		21,000			250,000
Proceeds from sale of lease and well equipment inventory		21,000			19,000
Proceeds from sale of support equipment		1,000			—
Net cash used in investing activities		(4,281,000	)		(2,117,000	)
Cash flows from financing activities:
Proceeds from exercise of common stock options		9,000			9,000
Proceeds from borrowing		1,905,000			380,000
Debt payments		(1,460,000	)		(380,000	)
Net cash provided by financing activities		454,000			9,000
Cash and cash equivalents:
Increase (decrease) in cash and cash equivalents		(814,000	)		468,000
Balance, beginning of year		892,000			424,000
Balance, end of year	$	78,000		$	892,000
Supplemental disclosure of cash flow information:
Cash paid for interest	$	8,000		$	1,000

See accompanying notes to consolidated financial statements.

31

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), was originally organized in July 1969 and became a public company in 1980. The Company is principally engaged in the acquisition, exploitation, development, operation and production of crude oil and natural gas. The Company’s 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 the accounts of Basic Earth Science Systems, Inc. (Basic or the Company) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

Oil and Gas Producing Activity. Basic follows the full cost method of accounting for its 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. With respect to its U.S. operations, Basic did not incur a ceiling limitation charge in either of the years ended March 31, 2006 (2006) or March 31, 2005 (2005). The Company did, however, take ceiling limitation charges of $85,000 and $240,000, respectively, in 2006 and 2005 related to its Canadian operations.

If a significant portion of Basic’s 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 properties. In 2006 and 2005, Basic reduced the carrying value of its oil and gas properties $21,000 and $250,000, respectively, as a result of the sale of its interest in certain oil and gas properties and equipment.

The majority of Basic’s oil reserves are located in the Williston basin area of North Dakota and Montana and in south Texas, and the majority of Basic’s gas reserves are located in Colorado’s Denver-Julesburg basin and in the on-shore Texas Gulf Coast region.

All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties owned by Basic. Depletion expense (excluding impairment charges related to the Canadian full cost pool ceiling limitation writedowns) per equivalent barrel of production was $3.70 and $2.15 for 2006 and 2005, respectively.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. There are many factors, including global events, which may influence the production, processing, marketing, and 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. Significant estimates include an estimate of the Company’s oil and gas reserves that is used to calculate depreciation and depletion expense, an estimate of Basic’s asset retirement obligation and an estimate of the valuation allowance with respect to the Company’s excess of deferred tax assets over deferred tax liabilities.

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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 3 and 4 below.

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

Long-Term Assets. The Company applies 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 2006 and 2005 there was no impairment recorded for long-lived assets.

Earnings Per Share. Basic 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 an entity 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 2006 and 2005:

	Years Ended March 31,
	2006		2005
Numerator:
Net income available to common shareholders	$	2,815,000	$	1,845,000
Denominator:
Denominator for basic earnings per share		16,732,611		16,586,309
Effect of dilutive securities:
Stock options		393,024		467,981
Denominator for diluted earnings per share		17,125,635		17,054,290

All options currently issued and outstanding were included in the computation of diluted earnings per share for both 2006 and 2005. See Note 7 below for further discussion of the Company’s stock options.

Stock Option Plan. In past years the Company applied Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (APB Opinion 25) and related interpretations in accounting for all stock option plans. Under APB Opinion 25, no compensation cost was recognized for stock options granted to employees and directors as the option price equaled or exceeded the market price of the underlying common stock on the date of grant.

In addition, SFAS No. 123, “Accounting for Stock-Based Compensation,” and related statements required the Company to provide pro forma information regarding net income and net income per share as if compensation costs for the Company’s stock option plan had been determined in accordance with the fair value based method prescribed in SFAS No. 123. As such, for all options granted through July 2003 (no options have been granted since July 2003) Basic estimated the fair value of stock awards on the grant date by using the Black-Scholes option-pricing model to provide such pro forma information.

With the issuance of Statement of Financial Accounting Standards No. 123(R), (SFAS No. 123(R)), in December 2004, the Company will be required in the future to recognize all equity-based compensation,

33

including stock option grants, as stock-based compensation expense in its Consolidated Statements of Operations based on the fair value of the compensation. Pro forma disclosure is no longer an alternative. The Company plans to adopt SFAS No. 123(R) in the June 30, 2006 quarter. The impact of the adoption of this standard cannot be predicted at this time because it will depend on levels of equity-based compensation, if any, to be granted in the future. For further discussion of SFAS No. 123(R) and the Company’s stock options, see the Recent Accounting Pronouncements section and Note 7 below.

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 2006 or 2005.

Cash and Cash Equivalents. For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, Basic considers 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.

Income Taxes. The Company accounts 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. Basic accounts for its hedging activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and related pronouncements. SFAS No. 133 requires companies to record derivatives on the balance sheet as assets or liabilities, measured at fair market value. Gains or losses resulting from changes in the values of these derivatives would be accounted for depending on the use of the derivative and whether it qualifies for hedge accounting. The key criterion for hedge accounting is that the hedging relationship must be highly effective in achieving offsetting changes in fair value or cash flows.

The Company periodically uses hedging techniques to limit its exposure to oil price fluctuations. Typically Basic will utilize either futures or option contracts. During the years ended March 31, 2006 and 2005 the Company did not participate in any hedging activities. Basic had no open futures or option contracts in place at either March 31, 2006 or March 31, 2005.

The Company recognizes the benefits of stabilizing volatile oil and gas prices via hedging instruments and will continue to monitor the futures market in an effort to identify, and participate in, hedging opportunities that the Company views as favorable.

The continuation of hedging activities may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events which the Company is not able to anticipate.

Recent Accounting Pronouncements. In December 2004 the FASB issued Statement of Financial Accounting Standards No. 123(R), (SFAS No. 123(R)), “Share-Based Payment,” a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123(R) supercedes APB Opinion 25, “Accounting for Stock Issued to Employees” and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows.” SFAS No. 123(R) requires a company to recognize equity-based compensation, including stock option grants, at fair value in the income statement, and discontinue accounting for equity-based compensation under APB Opinion 25, the intrinsic value method. SFAS No. 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as cash flow from financing activities rather than as cash flow from operations, as required currently. The requirements of this pronouncement are effective for fiscal periods beginning after June 15, 2005. The

34

Company plans to adopt SFAS No. 123(R) in the June 30, 2006 quarter, the first quarter of its year ending March 31, 2007.

In prior years, as permitted by SFAS No. 123, Basic accounted for equity-based compensation using APB Opinion 25 and, as such, reported such equity-based compensation on a pro forma basis only. The impact of adoption of SFAS No. 123(R) cannot be predicted at this time because it will depend on levels of equity-based compensation, if any, to be granted in the future. However, had SFAS No. 123(R) been applied to prior periods, the impact of this accounting standard would have approximated the effect of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in prior periods.

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.

2. Asset Retirement Obligation

Statement of Financial Accounting Standards No. 143 (SFAS No. 143), “Accounting for Asset Retirement Obligations” was adopted by the Company on April 1, 2003. SFAS No. 143 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 of the long-lived asset. Basic owns 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 the Company’s estimate of future asset retirement obligations for 2006 and 2005:

	Years Ended March 31,
	2006			2005
Asset retirement obligation at beginning of period	$	1,263,000		$	1,034,000
Liabilities settled during the period		(61,000	)		(50,000	)
New obligations for wells drilled and completed		29,000			11,000
Accretion of asset retirement obligation		74,000			70,000
Revisions to estimates		103,000			198,000
Asset retirement obligation at end of period	$	1,408,000		$	1,263,000
Current liability	$	37,000		$	88,000
Long-term liability		1,371,000			1,175,000
Asset retirement obligation at end of each period	$	1,408,000		$	1,263,000

The asset retirement expense recorded in the years ended March 31, 2006 and 2005 represents plugging and abandonment costs in excess of the estimated asset retirement obligation recorded with the adoption of SFAS No. 143. The Company based its initial estimates on its 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.

35

3. Other Current Assets

Other current assets at March 31, 2006 and 2005 consisted of the following:

	2006		2005
Lease and well equipment inventory	$	161,000	$	155,000
Drilling and completion cost prepayments		118,000		8,000
Other current assets		18,000		16,000
Total other current assets	$	297,000	$	179,000

The lease and well equipment inventory represents well-site production equipment owned by the Company that has been removed from wells that Basic operates. This occurs when the Company plugs a well or replaces 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 the Company from further transferring serviceable equipment to other wells that Basic operates on an as-needed basis.

Drilling and completion cost prepayments represent cash expenditures advanced by the Company to outside operators prior to the commencement of drilling and/or completion operations on a well. As for the prepayment balance at March 31, 2006, this amount represents cash advances for completion work scheduled to begin subsequent to year-end on two of Basic’s North Dakota wells.

4. Other Non-Current Assets

Other non-current assets at March 31, 2006 and 2005 consisted of the following:

	2006		2005
Lease and well equipment inventory	$	149,000	$	146,000
Plugging bonds		69,000		69,000
Total other non-current assets	$	218,000	$	215,000

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 Basic operates. This equipment inventory represents well-site production equipment owned by the Company that has either been purchased or has been removed from wells that Basic operates. 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 the Company to third parties who supply plugging bonds to federal and state agencies where Basic operates wells.

5. Long-Term Debt

Bank Debt. The Company’s current banking relationship, established in March 2002, is with American National Bank (the Bank), located in Denver, Colorado. Effective January 3, 2006 Basic and ANB 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. Also, the maturity date of the loan was extended for one year to December 31, 2007. Two other amendments include an interest rate reduction from prime plus two percent (2.00%) to prime plus one-quarter of one

36

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. The next borrowing base review is scheduled for July 2006.

Under its credit facility, the Company must maintain certain covenants with respect to various financial ratios and net worth criteria. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. One specific covenant requires Basic to maintain a net worth of at least $1,750,000, unless reduction below this value is due to a ceiling test write-down, in which case the Company must maintain a minimum net worth of $1,500,000. Another covenant obligates Basic 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. The Company was in compliance with all covenants at March 31, 2006.

This credit line is collateralized by a significant portion of the Company’s oil and gas properties and production. The interest rate at March 31, 2006 is the prime rate plus 0.25% compared to prime plus 2% at March 31, 2005. Basic’s effective annual interest rate was 8.00% and 7.75% at March 31, 2006 and 2005, respectively.

During both 2006 and 2005 Basic utilized its credit facility to fund portions of its drilling program and incurred interest charges of $7,000 and $1,000, respectively. As of March 31, 2006 and 2005 the outstanding balance on the line of credit was $445,000 and $0, respectively. As of June 9, 2006 the Company’s outstanding balance was $125,000. If necessary, the Company may borrow funds to reduce payables, finance recompletion or drilling efforts, fund property acquisitions, or pursue other opportunities the Company cannot contemplate at this time.

6. Commitments

The Company currently leases its office space in downtown Denver, Colorado from an independent third party. Effective March 1, 2003 Basic renewed the lease agreement for a five-year term through February 2008 and currently pays approximately $3,000 per month. Office rent expense was approximately $36,000 in both 2006 and 2005 and has provided for $36,000 and $33,000 for fiscal years ending March 31, 2007 and 2008, respectively.

In July 2004 Basic purchased a three-user license for its accounting software program and is currently under contract to pay $500 per month to lease space on the server where the software resides and to pay approximately $450 per month in software support and maintenance costs.

7. Shareholders’ Equity

Preferred Stock. The Company has 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 the shareholders of Basic 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 the Company’s common stock. The Plan was structured as a 10-year plan and, as such, ended on July 26, 2005. Options were granted to employees at the discretion of the compensation committee. During 2006 and 2005 no such options were granted. With respect to outside directors, on each July 27 anniversary date of the Plan through July 27, 2003, a non-discretionary grant of 25,000 options was issued to each outside director for services rendered. On July 27, 2004 Basic’s sole outside director declined to receive the 25,000 options that he was entitled to receive on that date. During the Plan’s existence, a total of 665,000 options were granted. As of March 31, 2006, of that amount, 50,000 options expired unexercised, 365,000 options remain unexercised and 250,000 options have been exercised; 200,000 options at a strike price of $0.078125 per share and 50,000 options at $0.065 per share.

37

Current option holders may exercise their options at prices ranging from $0.0325 to $0.175 per share (which was the market value at the date of grant) over a period not to exceed ten years from the grant dates, provided they remain directors or employees of the Company.

A summary of the status of the Company’s stock option plan and outstanding options as of March 31, 2006 and 2005 and changes during the years ending on those dates is presented below:

	2006						2005
				Weighted						Weighted
				Average						Average
				Exercise						Exercise
	Shares			Price			Shares			Price
Outstanding, beginning of year		490,000		$	0.0954			615,000		$	0.0892
Granted		—			—			—			—
Cancelled		—			—			—			—
Exercised		(125,000	)		(0.0755	)		(125,000	)		(0.0755	)
Outstanding, end of year		365,000		$	0.1023			490,000		$	0.0954
Options exercisable, end of year		365,000		$	0.1023			490,000		$	0.0954
Weighted average fair value of options granted during the year			$	—					$	—

The following table provides a summary of the stock options outstanding at March 31, 2006:

Options Outstanding									Options Exercisable
				Weighted
				Average			Weighted				Weighted
Range of		Number		Remaining			Average		Number		Average
Exercise		Outstanding		Contractual			Exercise		Exercisable		Exercise
Prices		at 3/31/06		Life			Price		at 3/31/06		Price
$	0.0325		50,000	2.33		years	$	0.0325		50,000	$	0.0325
	0.0420		50,000		3.33			0.0420		50,000		0.0420
	0.0900		50,000		1.33			0.0900		50,000		0.0900
	0.1150		90,000		1.67			0.1150		90,000		0.1150
	0.1325		50,000		4.33			0.1325		50,000		0.1325
	0.1500		25,000		6.33			0.1500		25,000		0.1500
	0.1600		25,000		7.33			0.1600		25,000		0.1600
	0.1750		25,000		5.33			0.1750		25,000		0.1750
$	.0325-0.1750		365,000	3.26		years	$	0.1023		365,000	$	0.1023

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8. Major Customers

Purchasers of 10% or more of Basic’s oil and gas production for 2006 and 2005 are as follows:

	2006			2005
Murphy Oil USA, Inc.		25	%		32	%
Valero Marketing & Supply Company		17	%		18	%
Plains Marketing LP		15	%		(a	)
Kerr-McGee Rocky Mountain Corporation		(a	)		10	%
Tesoro Refining and Marketing Company		(a	)		10	%

(a) Less than 10 percent

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

9. Income Tax

Due primarily to the intangible drilling and completion costs incurred in both 2006 and 2005 and the availability of net operating loss carryforwards in 2005, the Company recorded only a $13,000 income tax expense for 2006 and no income tax expense for 2005.

A reconciliation between the income tax provision at the statutory rate on income taxes and the income tax provision at March 31, 2006 and 2005 is as follows:

	2006			2005
Federal income tax provision at statutory rates	$	993,000		$	628,000
State income tax		87,000			57,000
Utilized net operating loss carryforward		—			(117,000	)
Change in valuation allowance		(819,000	)		(646,000	)
Other		(248,000	)		78,000
Income tax expense	$	13,000		$	—

The Company recorded a valuation allowance of $359,000 and $1,178,000 at March 31, 2006 and 2005, respectively, equal to the excess of deferred tax assets over deferred tax liabilities as it was unable to determine that these benefits are more likely than not to be realized. However, this is a significant estimate that is periodically re-evaluated by the Company. If Basic continues to be profitable, it is possible a portion, or all, of the Company’s deferred tax asset may be recorded as an asset on the Balance Sheet.

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

	For the Years Ended March 31,
	2006			2005
Allowance for doubtful accounts	$	26,000		$	26,000
Asset retirement obligation		537,000			469,000
Net operating loss carryforward		—			25,000
Other accruals		47,000			—
Statutory depletion carryforward		1,897,000			1,609,000
Total gross deferred tax assets		2,507,000			2,129,000
Valuation allowance		(359,000	)		(1,178,000	)
Net deferred tax asset		2,148,000			951,000
Deferred tax liability — depreciation and depletion		(2,148,000	)		(951,000	)
Net deferred taxes	$	—		$	—

As of March 31, 2006 the Company had fully utilized it net operating loss carryforward for tax purposes.

10. Related Party Transactions

It is Company policy that officers or directors may assign to, or receive assignments from, Basic in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. It is also the Company’s policy that officers or directors and Basic 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 2006 and 2005 none of the Company’s officers or directors participated with Basic in any of its oil and gas transactions. In prior years, Ray Singleton, president of Basic, has participated with the Company in certain acquisitions. With respect to his working interest in the five wells in which he currently participates, at March 31, 2006 and 2005 the Company had approximate receivables of $3,000 and $8,000, respectively, from Mr. Singleton for his share of operating expenses. Also at March 31, 2006 and 2005, the Company had approximate $3,000 and $5,000 payables to him, respectively, for his share of net revenue from these wells. At March 31, 2006 Mr. Singleton was current with respect to amounts owed to the Company.

11. 401(k) Plan

The Company has a savings plan (the Plan) which 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 Plan. Basic matches 100% of the employee’s contributions up to 3% of the employee’s salary. Contributions are fully vested when made. In 2006 and 2005, Basic contributed approximately $14,000 and $13,000, respectively, to the Plan.

12. 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, 2006 and 2005 are as follows:

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	At March 31,
	2006			2005			2004
Developed properties	$	24,257,000		$	22,821,000		$	20,524,000
Undeveloped properties		2,881,000			32,000			290,000
		27,138,000			22,853,000			20,814,000
Accumulated depreciation and depletion		(17,250,000	)		(16,794,000	)		(16,538,000	)
Net capitalized oil and gas property	$	9,888,000		$	6,059,000		$	4,276,000

Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2006, 2005 and 2004 are summarized as follows:

	Years Ended March 31,
	2006		2005		2004
Development costs	$	2,881,000	$	1,311,000	$	693,000
Exploration costs		1,394,000		1,033,000		191,000
Acquisitions:
Proved		—		2,000		110,000
Unproved		—		—		—
Total	$	4,275,000	$	2,346,000	$	994,000

Typically drilling and completion projects in the oil and gas industry will span a period of time such that the results of these exploration and development activities undertaken during any one particular year may not be reflected in oil and gas reserve estimates until subsequent periods. This is particularly true if a number of projects are started late in the year as was the case for Basic in fiscal 2006. Of the $4,275,000 of costs incurred during 2006, approximately $3,277,000 was related to projects undertaken during the third and fourth quarters of the year. As such, at year end Basic had a number of projects in various stages of drilling and/or completion for which enough data was not available to properly evaluate and add to the Company’s reserve base at March 31, 2006. Of this $4,275,000, approximately two-thirds, or $2,850,000 relates to properties that have not yet been evaluated for purposes of estimating and adding reserves, and therefore, the results of which are not reflected in the tables in Note 13 immediately following.

13. Unaudited Oil and Gas Reserve Information

At March 31, 2006 and 2005, 93 and 90 percent, respectively, of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firms Ryder Scott Company and Heinle & Associates, Inc., respectively. The remaining 7 and 10 percent of the reserve estimates, respectively, were prepared internally by Basic’s management. The Company cautions 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 93 percent of the Company’s oil production and 96 percent of its gas production in 2006. Other properties contributed only marginal amounts to Basic’s total production and management has elected not to incur the additional expense of evaluating these properties for inclusion in its estimated oil and gas reserves.

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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.

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			Natural
	liquids			gas
	(Bbls)			(Mcf)
Proved developed reserves at March 31, 2004		858,000			1,105,000
Revisions of previous estimates		152,000			(205,000	)
Extensions and discoveries		138,000			134,000
Sales of reserves in place		—			—
Improved recovery		—			—
Purchase of reserves		—			—
Production		(92,000	)		(164,000	)
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

All of the Company’s oil and gas reserves at March 31, 2006 are classified as Proved Developed, Producing. Of the reserves at March 31, 2005, 36,000 barrels (3% of total oil reserves) and 20,000 Mcf (2% of total gas reserves) were classified as Proved Developed, Non-Producing. All other reserves were Proved Developed, Producing. Despite management’s belief that proved undeveloped reserves may exist, Basic did not record any Proved Undeveloped reserves at March 31, 2006 or 2005.

The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to Basic’s 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, 2006 and 2005. The future production and development costs represent the estimated future expenditures to be incurred in developing and producing 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.

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Standardized Measure of Estimated Discounted Future Net Cash Flows

	At March 31,
	2006			2005
Future cash inflows	$	64,022,000		$	63,581,000
Future cash outflows:
Production cost		(29,618,000	)		(28,623,000	)
Development cost		—			(3,000	)
Future net cash flows before income taxes		34,404,000			34,955,000
Future income taxes		(8,142,000	)		(9,624,000	)
Future net cash flows		26,262,000			25,331,000
Adjustment to discount future annual net cash flows at 10%		(11,230,000	)		(10,512,000	)
Standardized measure of discounted future net cash flows	$	15,032,000		$	14,819,000

The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for 2006 and 2005.

Changes in Standardized Measure of Estimated Discounted Net Cash Flows

	Years Ended March 31,
	2006			2005
Standardized measure, beginning of period	$	14,819,000		$	7,457,000
Sales of oil and gas, net of production cost		(4,031,000	)		(2,908,000	)
Net change in sales prices, net of production cost		768,000			6,609,000
Discoveries, extensions and improved recoveries, net of future development cost		2,294,000			5,061,000
Change in future development costs		4,000			12,000
Development costs incurred during the period that reduced future development cost		—			20,000
Purchase of reserves		—			—
Sales of reserves in place		—			—
Revisions of quantity estimates		(559,000	)		1,770,000
Accretion of discount		1,948,000			892,000
Net change in income taxes		957,000			(3,208,000	)
Changes in rates of production and other		(1,168,000	)		(886,000	)
Standardized measure, end of period	$	15,032,000		$	14,819,000

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ITEM 8
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 8A
CONTROLS AND PROCEDURES

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

As of March 31, 2006 the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including Ray Singleton, Chief Executive Officer, and David Flake, Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, Messrs. Singleton and Flake have concluded that the Company’s disclosure controls and procedures are effective for the purposes discussed above.

There have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s fourth quarter of the current fiscal year that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part III

ITEM 9
DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
PERSONS; COMPLIANCE WITH SECTION 16(a)
OF THE EXCHANGE ACT

Information concerning this item will be in Basic’s 2006 Proxy Statement, which is incorporated herein by reference.

ITEM 10
EXECUTIVE COMPENSATION

Information concerning this item will be in Basic’s 2006 Proxy Statement, which is incorporated herein by reference.

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ITEM 11
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT

Information concerning this item will be in Basic’s 2006 Proxy Statement, which is incorporated herein by reference.

ITEM 12
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information concerning this item will be in Basic’s 2006 Proxy Statement, which is incorporated herein by reference.

ITEM 13
EXHIBITS AND REPORTS ON FORM 8-K

(a) 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)a	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.
10(ii)1	Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985
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 (David Flake, Chief Financial Officer)
32.1	Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
32.2	Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (David Flake, Chief Financial Officer).

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.

45

(b) Reports on Form 8-K

Date	Document
October 28, 2005	The Company provided an update of its onshore Texas Gulf Coast opertions.
October 31, 2005	The Company announced that it had commenced drilling the State 16-H horizontal well in McKenzie County, North Dakota.
December 14, 2005	The Company reported that it had completed drilling operations on the State 16-1H and would attempt a completion in the Bakken formation.
January 27, 2006	The Company announced that its Bakken completion efforts in the State 16-1H were unsuccessful and that it would come uphole and attempt a completion in the Rival formation.
February 7, 2006	The Company reported that it had drilled and completed the Halvorsen 21X-36 horizontal well in Richland County, Montana. Following a hydraulic fracture stimulation, the well was placed on production. The Company also reported significant production declines in its Johnson 3-21H horizontal well in Richland County and that had been shut in order to perform downhole diagnostic pressure tests.
March 1, 2006	The Company announced that it had completed drilling operations on the LM #1 Rival formation test in McKenzie County, North Dakota and had commenced drilling the LM #2, another McKenzie County Rival test. Basic was currently waiting on a completion rig on the LM #1. The Company also provided updates on the State 16-1H, the Lynn #1, the Lynn #2 and the Lynn #3H wells.
March 14, 2006	The Company responded to inquiries concerning elevated oil price differentials relative to West Texas Intermediate benchmark crude oil prices and the effect to-date that these increased price differentials have had on Basic.
March 15, 2006	The Company reported that it had successfully reached the planned total depth on the LM #2 vertical Rival test well but that Basic and its partners elected reposition the drilling assembly uphole in order to take the wellbore horizontally into the Rival formation.
May 9, 2006	The Company announced that it had begun completion operations on the LM #2 and that the well initially flowed 147 barrels of oil per day. Basic also reported that it had hydraulically stimulated the LM #1 but that the well was making less than commercial rates of production and had been shut in pending further evaluation.

ITEM 14
PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information concerning this item will be in Basic’s 2006 Proxy Statement, which is incorporated herein by reference.

46

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
/s/ Ray Singleton	June 21, 2006
Ray Singleton, President
/s/ David Flake	June 21, 2006
David Flake, Chief Financial Officer and
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
/s/ David Flake	June 21, 2006
David Flake, Director
/s/ Edgar J. Huffman	June 21, 2006
Edgar J. Huffman, Director and
Audit Committee Chairman
/s/ Ray Singleton	June 21, 2006
Ray Singleton, Director

47

EXHIBIT INDEX

(a) 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)a	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.
10(ii)1	Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985
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 (David Flake, Chief Financial Officer)
32.1	Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
32.2	Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (David Flake, Chief Financial Officer).

¹ Previously filed and incorporated herein by reference

48