e10ksb

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, 2007


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: $7,167,000

As of June 18, 2007 16,955,487 shares of the registrant’s common stock were outstanding and the aggregate market value of such common stock held by non-affiliates was approximately $16,829,000. The proxy statement for the 2007 annual meeting is incorporated by reference into Part III.

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’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

The three components of Basic’s 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.

Basic’s primary exploration focus is in the Montana and North Dakota portions of the Williston basin. The Company has been involved in the Williston basin since the early 1980’s and only in south Texas does the Company have a longer history. As such, 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.

Over the past five years, the Company’s strategy focused almost entirely on exploration and development drilling. During this time field service costs, particularly drilling and completion costs, have been escalating. These increases have been greatly exacerbated by the shortage of experienced rig crews and the longer times necessary to safely complete operations. Because of these and other factors, our preference for drilling over acquisitions has been waning. Thus, Basic intends to take a more balanced approach and increase its acquisition efforts relative to previous years.

Areas of Focus

Williston Basin

The Williston basin continues to be the Basic’s primary area of focus both in terms of future cashflow from existing properties and future expenditures. In the coming year, the Company intends to increase its efforts to acquire properties in the Williston basin (especially in the northern portion of the basin) while it continues to exploit its ongoing drilling prospects. From a drilling perspective, Basic has three areas within the Williston basin where it expects drilling operations to commence or continue during the current fiscal year. These areas are the Company’s on-going Banks prospect in McKenzie County, North Dakota, the on-going horizontal Madison drilling efforts in the TR Madison unit in Billings County, North Dakota and the Company’s South Flat Lake prospect in Sheridan County, Montana. The Company cautions that the following expectations may be altered by subsequent events or other, more attractive opportunities that may present themselves in the future.

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 this purchase was a plan to position the Company in the developing, though unproven, extension of the Bakken horizontal play into North Dakota. 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, (which was subsequently converted from a vertical wellbore to a horizontal producer), Basic drilled three wells on this prospect: two horizontal Rival producers (both of which remain unstimulated) and a temporarily abandoned well which is still being evaluated for further development (see discussion below). In addition, 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 in this immediate area or a breakthrough in stimulation technology or application is made, Basic and its partners have little interest in pursuing Bakken development on this prospect.

TR Madison Unit Prospect — Billings County, North Dakota. In May 2003 the North Dakota Industrial Commission created the TR Madison Unit for the purpose of enhancing the ultimate recovery from the Madison formation in the TR Field. Approximately nineteen existing wells were originally included in the Unit. By virtue of its interest in one of these wells Basic acquired a 1.075% working interest (0.833% net revenue interest) in the Unit. During the previous four years, five new horizontal wells have been drilled and four original vertical wells have had horizontal laterals added. Two of these new horizontal wells were drilled in the year ended March 31, 2007 (fiscal 2007). While the Company’s interest in this effort is relatively small, this property has now become Basic’s 10^th largest producer in terms of cash flow. More importantly these gains have been made with relatively low risk and low cost (relative to Basic’s cash position).

South Flat Lake Prospect – Sheridan County, Montana. The Company has acquired leases on approximately 4,200 gross acres (1,900 net) in northern Sheridan County near the Flat Lake Field. Developed by a geologist on retainer to Basic, South Flat Lake represents the first exploration prospect Basic has generated in more than a decade. To defray the cost of this effort, land, legal and geologic costs were funded equally by Basic and its 50% partner in this venture, an unrelated, non-public company. Basic and its partner expect to eventually sell a portion of this prospect to others to help defray their share of the cost of drilling. As an exploratory venture, this prospect is considered high risk and no assurance of its ultimate success can be offered.

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. Over the past several years, Basic and its partner have deepened three Codell wells to the J-Sand formation. Basic has a 3% to 5% overriding royalty interest in the 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. In fiscal 2007, the Antenna-Federal property produced 43% of the Company’s gas production.

Onshore Gulf Coast. During the past few years, the Company participated in five wells in this area; primarily pursuing “3-D Bight Spots”. As noted above, the Company’s involvement in these efforts was pursued strictly to enhance Basic’s exposure to natural gas projects. In fiscal 2007, one of these properties, the Martin #1-D, produced approximately 23% of the Company’s gas production. Basic remains interested in Yequa “3-D Bright Spot” prospects and intends to look at and evaluate additional 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

Christmas Meadows Prospect – Summit County, Utah. In fiscal 2007, Basic participated with Double Eagle Petroleum Company (Double Eagle) in one of the more exciting, true wildcat projects in the Rocky Mountain region: Christmas Meadows. The Table Top Unit #1 reached approximately 16,000 and encountered the Dakota formation before operations were curtailed in February 2007. The well was plugged back to the base of the intermediate casing to protect the wellbore. Double Eagle is evaluating the feasibility of re-entering the wellbore with a larger rig and taking this well down to approximately 18,000 feet to test the deeper Nugget formation. The Company expects to receive a proposal in the next few months from Double Eagle to return to Christmas Meadows. However, until Basic receives this proposal and has an opportunity to evaluate the engineering details, the geological risk and the cost estimates for this effort, Basic’s decision to remain involved in this re-entry is not assured. Basic has a 1.5% interest in all future operations in this wellbore and in any future operations on the Christmas Meadows prospect.

Contemplated Activities

In addition to the discussion in Areas of Focus described above, the Company anticipates pursuing the following activities in fiscal 2008 (year ending March 31, 2008).

Williston Basin

On its Banks prospect, Basic expects to receive three proposals in the near future. First, a proposal to stimulate the LM #2 with gelled acid. This effort is expected to be undertaken this summer and is estimated to cost $40,000 to Basic’s 19.33% interest. The second expected proposal would re-enter the temporarily abandoned LM #1 and drill a horizontal lateral to evaluate the remaining acreage within that section. Basic’s working interest in this effort, which is expected to be undertaken this summer or early fall, is estimated to be approximately 12.5%, but will not be finalized until a title opinion is received. If this interest estimate is correct, Basic’s drilling cost will be approximately $140,000. The third expected proposal will be to drill a new well in Section 4 or 5, immediately north of the Pederson #1-10H, located in Section 10 and operated by Zenergy Inc. This well is expected to cost approximately $3.5 million to drill and complete. However, until the exact location is determined, Basic’s percentage interest and proportionate cost can not be quantified.

In the TR Madison Unit, the Company expects to drill one additional well this summer. The well is expected to cost $2.5 Million or $26,500 to Basic’s 1% interest.

In Montana, Basic and its 50% partner expect to drill a vertical Red River test on the South Flat Lake prospect in fiscal 2008. If successful, it is possible that as many as 4 development wells could be drilled. The initial well is expected to cost approximately $1.5 million dollars to drill and complete. While Basic now owns and could participate for its 50% interest in this prospect, if the Company and its partner sell a portion of this prospect as they intend, Basic’s interest would be proportionately reduced. Basic expects to be the operator of the property.

Other Areas

On its Antenna Federal property in Weld County, Colorado, Basic has disclosed for a number of years plans to deepen three additional Codell formation wells to the J-Sand formation. These efforts were never undertaken due to various issues including repeated sales/mergers of Basic’s partner on the property and Bureau of Land Management permitting requirements. In March 2006 the Colorado Oil and Gas Conservation Commission promulgated Rule 318Ae which effectively allows 20 acre spacing in the Wattenburg Field; essentially 32 wells per section. The Company has had several meetings with the current operator, Kerr McGee, Rocky Mountain Group. Based on these discussions Basic expects that it and Kerr McGee will drill 16 new wells in the section. Basic will initially have a working interest in 11 of these new wells and it’s interest will vary from 15% to 60% depending on where each well is located in the section. Kerr McGee expects to launch drilling operations in the 2^nd or 3^rd quarter of fiscal 2008 and drill all 16 wells back-to-back. Some of these wells will only be drilled to the Codell formation; others will be drilled to the deeper J-Sand, but will initially only be produced from the Codell formation. On those wells drilled to the J-Sand, Basic will only pay its proportionate share of the incremental drilling and completion costs to the Codell formation (potentially as low as 15%). Only once the well is completed and productive in the J-Sand will Basic pay its proportionate share (potentially as high as 60%) of just the incremental drilling and completion costs from the Codell to the J-Sand. While Basic will initially only have a working interest in 11 wells, once all the J-Sand wells have been placed on production, Basic will have a working interest in 14 of the 16 new wells. The Company expects its proportionate share of initial drilling costs to be $1.75 million. At this point, Basic believes that it is highly likely that the preceding will occur. However, given the history of this property, its numerous changes in ownership and its complex land issues there can be no assurances in this matter and these plans may again be altered by unforeseen events.

Basic is continually evaluating other drilling and acquisition opportunities for possible participation. Typically, at 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 2007, Basic sold 60% of its oil and gas production to three purchasers: Plains Marketing LP (22%), Murphy Oil USA, Inc. (20%) and Valero Marketing & Supply Co. (18%). 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 over a decade, Basic did not develop an in-house geologic or geophysical infrastructure, as have many of its competitors. Rather than incur the time and expense to develop in-house capability, Basic chose 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 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 related to the discharge of materials into, and the protection of, the environment. These laws and regulations, among other things, may impose liability on the owner or the lessee for the cost of pollution cleanup resulting from operations, subject the owner or lessee to liability for pollution damages, require the suspension or cessation of operations in affected areas and impose restrictions on injection into subsurface formations in order to prevent the contamination of ground water. All but three of the disposal wells that 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 $3.50 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 and reached $7 per barrel for production from the northern portion of the Williston basin and as much as $30 per barrel for production from both the southern portion of the Williston basin and Wyoming. For March 2007 the price differential ranged from $2.50 to $14.00 below the U.S. crude spot price. There are several factors leading to this continuing price differential. 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.

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 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, 2007 the Company had seven full-time employees: four at its main office in Denver and three 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 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, 2007 Basic owned a working interest in 83 producing oil wells and 10 producing gas wells. The Company currently operates 52 of these wells in five states: North Dakota, Montana, Colorado, Texas and Wyoming. These operated wells contributed approximately 49% of both Basic’s total liquid hydrocarbon sales and total natural gas sales in fiscal 2007. 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		1		0.01		0.10
Montana		17		—		8.75		—
North Dakota		41		—		9.03		—
Texas		23		2		20.66		0.18
Wyoming		1		—		0.47		—


Total		83		10		38.92		4.48

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, 2007 Basic’s estimated proved developed oil and gas reserves in barrels of oil equivalent (BOE) was 1,185,000, a 6.4% increase over the prior year’s estimated proved developed oil and gas reserves of 1,114,000 BOE. However, due to increases in estimated production costs, the Company’s standardized measure of discounted future net cash flows was $14,624,000, a 2.7% decrease from the prior year’s standardized measure of discounted future net cash flows of $15,032,000. 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, 2007:


	Net Oil		Net Gas
	(Bbls)		(Mcf)		BOE		%
Williston Basin
Operated		364,000		95,000		379,000		32.0
Non-Operated		276,000		204,000		310,000		26.2


		640,000		299,000		689,000		58.2


South Texas/Onshore Gulf Coast
Operated		329,000		—		329,000		27.7
Non-Operated		—		230,000		39,000		3.3


		329,000		230,000		368,000		31.0


D-J Basin
Operated		12,000		596,000		118,000		9.4
Non-Operated		1,000		13,000		4,000		0.3


		13,000		609,000		122,000		9.7


Other Areas
Operated		13,000		—		13,000		1.1
Non-Operated		—		—		—		—


		13,000		—		13,000		1.1


Total		995,000		1,138,000		1,185,000		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 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		51		—		—
Montana		6,161		2,773		5,623		3,049
North Dakota		14,263		2,385		23,632		1,534
Texas		3,080		2,486		—		—
Utah		—		—		35,945		719
Wyoming		1,555		329		40		1


Total		26,386		8,408		65,240		5,303

Field Service Equipment

At March 31, 2007 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.

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, 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

Year Ended March 31, 2007

First Quarter	$	2.85	$	2.00
Second Quarter		2.29		1.66
Third Quarter		2.22		1.77
Fourth Quarter		1.90		1.52

The closing bid price on June 18, 2007 was $1.42. 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 18, 2007, Basic had approximately 2,118 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 2008. In addition, as mentioned in the “Debt” section below, Basic has an available borrowing capacity of $4,000,000 as of June 18, 2007.

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. Effective December 31, 2006 the loan agreement was amended again to extend the maturity date of the credit agreement to December 31, 2008.

During both the years ended March 31, 2007 (2007) and March 31, 2006 (2006) Basic utilized its credit facility to fund portions of its drilling program and incurred interest charges of $6,000 and $7,000, respectively. Basic’s effective annual interest rate was 8.50% and 8.00% at March 31, 2007 and 2006, respectively. On June 18, 2007 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 re-completion or drilling efforts, fund property acquisitions, or pursue other opportunities the Company cannot envision at this time. See Note 5 to the Consolidated Financial Statements for a more detailed discussion of the Company’s bank credit facility.

Hedging. In the past, the Company has used hedging techniques to limit its exposure to oil price fluctuations. Typically Basic will utilize either futures or option contracts. During 2007 and 2006 the Company did not participate in any hedging activities. The Company had no open futures or option contracts in place at either March 31, 2007 or March 31, 2006. Additional information concerning the Company’s hedging activities appears in Note 1 to the Consolidated Financial Statements.

Working Capital. At March 31, 2007 the Company had a working capital surplus of $2,057,000 (a current ratio of 2.03:1) compared to a working capital surplus at March 31, 2006 of $217,000 (a current ratio of 1.15:1). The primary difference from 2006 to 2007 was a substantial increase in cash and cash equivalents resulting from the combined effect of improved cash flow from operations with a drop in the amount of funds used in investing activities.

Cash Flow. As mentioned above, the Company’s primary source of funding is the cash flow from its operations. Cash provided by operating activities jumped 42% from $3,013,000 in 2006 to $4,283,000 in 2007. This increase was primarily due to a combination of improved oil and gas production and higher average oil prices.

Net cash used in investing activities dropped 67% from $4,281,000 in 2006 to $1,413,000 in 2007. This decrease underscores the fact that, since Basic has a minority, non-operated interest in most of its current portfolio of exploration and development projects, it has little or no control over the pace at which wells are drilled and/or re-completed.

Periodically during 2007 the Company utilized debt financing to fund short-term working capital needs. With a strong cash flow from operations and a significant amount of available cash, Basic has not borrowed on its line of credit since June 2006. Cash provided by financing activities was $454,000 in 2006 while cash used for financing activities was $425,000 in 2007, principally for repayment of debt.

Capital Expenditures. During 2007 the Company’s capital expenditures were primarily focused in two specific areas: the Montana and North Dakota portions of the Williston basin and the Christmas Meadows prospect in Summit County, Utah. In the Williston basin the Company’s efforts were concentrated in three areas: Richland County, Montana, the Indian Hill Field in McKenzie County, North Dakota and the Banks prospect also located in McKenzie County, North Dakota. Total capital expenditures during 2007 for oil and gas property and equipment and various leasehold interests were $1,703,000. Eighty-eight percent of these costs can be broken down between the specific areas of focus as follows:

	•		Banks Prospect — McKenzie County, North Dakota. Basic spent a total of $739,000 for additional drilling and/or completion operations on the prospect’s first three wells. The State 16-1H well began producing near the end of 2006, the LM #2 well was placed on production near the beginning of 2007 and the LM #1 is currently shut-in and being evaluated for further development.

	•		Horizontal Bakken — Richland County, Montana. The Company invested $298,000 in this area: $258,000 to drill a second horizontal lateral in the Johnson 3-21H well and $40,000 of additional completion costs on the Halvorsen 21X-36.

	•		Indian Hill Field — McKenzie County, North Dakota. A total of $154,000 was used to finance re-completion work on the Lynn #2 and Lynn#3H wells.

	•		Other Areas — Summit County, Utah. The Company invested $302,000 for its 2% working interest to drill the Table Top Unit #1 well that is operated by Double Eagle Petroleum Company. In February 2007 drilling operations were halted after encountering the Dakota formation at approximately 16,000 and the well was plugged back to the base of the intermediate casing.

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

The Company’s capital expenditure budget for 2007 anticipated meeting or exceeding fiscal 2006 capital expenditures of $4.3 million. However, Basic has a minority interest in most of its current portfolio of exploration and development projects and, as such, had little or no control over the pace at which wells were drilled and/or re-completed. The Company believes that the unspent portion of its 2007 capital budget will be deployed in fiscal 2008.

Basic is continually evaluating exploration, development and acquisition 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 other events which the Company is not able to anticipate.

Divestitures/Abandonments. The Company plugged three wells during 2007 and incurred some additional costs pertaining to the abandonment of wells that were plugged in prior periods.

Impact of Inflation. Inflation has not had a material impact on the Company in recent years because of the relatively low rates of inflation in the United States.

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, 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 2007 Compared with Fiscal 2006

Overview. Net income for the year ended March 31, 2007 (2007) was $2,500,000 compared to net income of $2,815,000 for the year ended March 31, 2006 (2006), an 11% decrease. Earnings for 2007 were greatly impacted by the current year income tax expense and the provision for deferred income taxes following utilization of the remaining tax net operating loss carry-forward in 2006.

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

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

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

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

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

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

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

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

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

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

Income Taxes. In 2007 the Company recorded income tax expense of $907,000 comprised of a current year income tax provision of $326,000 and a deferred income tax provision of $581,000. This compares to a 2006 income tax expense of $13,000. At March 31, 2006 Basic had a net deferred tax asset of $359,000. However, with a combination of the Company’s net income from operations over the past few years and the expensing of intangible drilling and completion costs for tax purposes during these years, Basic’s net deferred tax asset has been utilized and the Company now is in a deferred tax liability position. Going forward, under a scenario of sustained net income from operations, Basic anticipates recording an income tax expense each year that should approximate 38%. The effective tax rate for 2007 was 27% of pre-tax income, which differs from the expected future tax rate primarily because of the utilization during 2007 of the Company’s remaining net deferred tax asset carried forward from 2006, which had previously been fully offset by a valuation allowance due to the uncertainty as to its utilization.

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.


	2007		2006		2005
Production:
Oil (barrels)		104,200		99,900		91,600
Gas (Mcf)		155,800		140,800		163,700
Revenue: (in thousands)
Oil	$	6,115	$	5,530	$	3,934
Gas		1,014		1,065		893


Total		7,129		6,595		4,827
Less: Total production expense (in thousands)¹		2,422		2,564		1,919


Gross profit (in thousands)	$	4,707	$	4,031	$	2,908


Depletion expense (in thousands)⁴	$	631	$	456	$	256
General and administrative expense (in thousands)	$	546	$	524	$	416

Average sales price²
Oil (per barrel)	$	58.70	$	55.35	$	42.94
Gas (per Mcf)		6.51		7.56		5.45
Average production expense^1,2,3		18.61		20.78		16.14
Average gross profit^2,3		36.17		32.66		24.45
Average depletion expense^2,3,4		4.85		3.70		2.15
Average general and administrative expense^2,3		4.20		4.24		3.50


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, and the estimate of its asset retirement obligations.

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 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-two percent of Basic’s reported oil and gas reserves at March 31, 2007 are based on estimates prepared by an independent petroleum engineering firm. The remaining eight percent of the Company’s oil and gas reserves were prepared in-house. See also Note 13 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.

Off Balance Sheet Transactions, Arrangements or Obligations

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

Recent Accounting Pronouncements

In September 2006 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 157 (SFAS No. 157). The Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The adoption of SFAS No. 157 is not expected to have a material effect on the Company’s financial position, results of operations, or cash flows.

In July 2006 the FASB released FASB Interpretaion No. 48 — “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN No. 48). FIN No. 48 clarifies the accounting and reporting for uncertainties in income taxes recognized in an entity’s financial statements in accordance with Statement of Financial Accounting Standards No. 109 — “Accounting for Income Taxes” and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 is effective for fiscal years beginning after December 15, 2006 with the impact of adoption to be reported as a cumulative effect of an accounting change. The adoption of FIN No. 48 is not expected to have a material effect on the Company’s financial position, results of operations, or cash flows.

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, 2007 and 2006, 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, 2007 and 2006, 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 28, 2007

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets


	At March 31,
	2007			2006
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	744,000		$	389,000
Accrued liabilities		1,245,000			1,084,000


Total current liabilities		1,989,000			1,473,000


Long-term liabilities:
Long-term debt		—			445,000
Deferred tax liability		581,000			—
Asset retirement obligation		1,802,000			1,372,000


Total long-term liabilities		2,383,000			1,817,000


Commitments (Note 6)

Shareholders’ equity:
Preferred stock, $.001 par value Authorized - 3,000,000 shares Issued - 0 shares		—			—
Common stock, $.001 par value Authorized - 32,000,000 shares Issued - 17,304,752 shares at March 31, 2007 and 17,129,752 at March 31, 2006		17,000			17,000
Additional paid-in capital		22,730,000			22,710,000
Treasury stock (349,265 shares); at cost		(23,000	)		(23,000	)
Accumulated deficit		(11,644,000	)		(14,144,000	)


Total shareholders’ equity		11,080,000			8,560,000


Total liabilities and shareholders’ equity	$	15,452,000		$	11,850,000

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

Consolidated Statements of Operations


	Years Ended March 31,
	2007			2006
Revenues:
Oil and gas sales	$	7,129,000		$	6,595,000
Well service revenue		38,000			20,000


Total revenues		7,167,000			6,615,000


Expenses:
Oil and gas production		1,935,000			2,104,000
Production tax		487,000			460,000
Well servicing expenses		41,000			24,000
Depreciation, depletion and impairment		640,000			550,000
Accretion of asset retirement obligation		108,000			74,000
Asset retirement expense		125,000			63,000
General and administrative		546,000			524,000


Total expenses		3,882,000			3,799,000


Income from operations		3,285,000			2,816,000


Other Income (Expense):
Interest and other income		50,000			23,000
Fuel purchase overcharge refund		79,000			—
Interest and other expenses		(7,000	)		(11,000	)


Total other income		122,000			12,000


Income before income taxes		3,407,000			2,828,000


Current income tax expense		326,000			13,000
Provision for deferred income taxes		581,000			—


Total income taxes		907,000			13,000


Net income	$	2,500,000		$	2,815,000


Per share amounts:
Basic	$	0.149		$	0.168


Diluted	$	0.146		$	0.164


Weighted average common shares outstanding:
Basic		16,825,076			16,732,611
Diluted		17,129,537			17,125,635

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows


	Years Ended March 31,
	2007			2006
Increase (decrease) in cash and cash equivalents:

Cash flows from operating activities:
Net income	$	2,500,000		$	2,815,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		640,000			550,000
Deferred tax liability		581,000			—
Accretion of asset retirement obligation		108,000			74,000
Change in:
Net accounts receivable		54,000			(308,000	)
Other assets		70,000			(86,000	)
Accounts payable and accrued liabilities		321,000			(33,000	)
Asset retirement obligation		—			(6,000	)
Other		9,000			7,000


Net cash provided by operating activities		4,283,000			3,013,000


Cash flows from investing activities:
Capital expenditures:
Oil and gas property		(1,703,000	)		(4,271,000	)
Support equipment		(38,000	)		(8,000	)
Insurance settlements		208,000			—
Proceeds from sale of oil and gas property and equipment		146,000			21,000
Proceeds from sale of support equipment		—			1,000
Other		(26,000	)		(24,000	)


Net cash used in investing activities		(1,413,000	)		(4,281,000	)


Cash flows from financing activities:
Proceeds from exercise of common stock options		20,000			9,000
Proceeds from borrowing		565,000			1,905,000
Debt payments		(1,010,000	)		(1,460,000	)


Net cash provided by (used in) financing activities		(425,000	)		454,000


Cash and cash equivalents:
Increase (decrease) in cash and cash equivalents		2,445,000			(814,000	)
Balance, beginning of year		78,000			892,000


Balance, end of year	$	2,523,000		$	78,000


Supplemental disclosure of cash flow information:
Cash paid for interest	$	7,000		$	8,000
Increase in oil and gas property due to asset retirement obligation	$	512,000		$	132,000

See accompanying notes to consolidated financial statements.

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 had its first public offering 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, 2007 (2007) or March 31, 2006 (2006). The Company did, however, take a ceiling limitation charge of $85,000 in 2006 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 property. In 2007 and 2006, Basic reduced the carrying value of its oil and gas property $146,000 and $21,000, respectively, as a result of the sale of its interest in certain oil and gas property and equipment. Also in 2007, the Company received insurance settlements of $161,000 and $47,000 related to contractor negligence coverage and blowout coverage, respectively. The carrying value of Basic’s oil and gas property was reduced by the $208,000 received from these settlements.

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 portions of the on-shore 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 writedown) per equivalent barrel of production was $4.85 and $3.70 for 2007 and 2006, 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 deferred income taxes.

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 2007 and 2006 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 the Company and is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options. The following is a reconciliation of basic and diluted earnings per share for 2007 and 2006:


	Years Ended March 31,
	2007		2006
Numerator:
Net income available to common shareholders	$	2,500,000	$	2,815,000


Denominator:
Denominator for basic earnings per share		16,825,076		16,732,611
Effect of dilutive securities:
Stock options		304,461		393,024


Denominator for diluted earnings per share		17,129,537		17,125,635

All options currently issued and outstanding were included in the computation of diluted earnings per share for both 2007 and 2006. See Note 7 below for further discussion of the Company’s stock options.

Stock Option Plan. 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, including stock option grants, as stock-based compensation expense in its Consolidated Statements of Operations based on the fair value of the compensation. The Company adopted SFAS No. 123(R) in the June 30, 2006 quarter. Since the Company’s stock option plan expired in July 2005 and no options have been granted since July 2003, Basic did not record any stock-based compensation expense in either 2007 or 2006. See Note 7 below for further discussion of the Company’s stock options.

Comprehensive Income. Comprehensive income is comprised of net income and all changes to the Consolidated Statements of Shareholders’ Equity, except those due to investments by shareholders, changes in additional paid-in capital and distributions to shareholders. There was no difference between net income and comprehensive income for 2007 or 2006.

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.

In the past, the Company has used 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, 2007 and 2006 the Company did not participate in any hedging activities. Basic had no open futures or option contracts in place at either March 31, 2007 or March 31, 2006.

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 September 2006 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 157 (SFAS No. 157). The Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The adoption of SFAS No. 157 is not expected to have a material effect on the Company’s financial position, results of operations, or cash flows.

In July 2006 the FASB released FASB Interpretaion No. 48 – “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN No. 48). FIN No. 48 clarifies the accounting and reporting for uncertainties in income taxes recognized in an entity’s financial statements in accordance with Statement of Financial Accounting Standards No. 109 – “Accounting for Income Taxes” and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 is effective for fiscal years beginning after December 15, 2006 with the impact of adoption to be reported as a cumulative effect of an accounting change. The adoption of FIN No. 48 is not expected to have a material effect on the Company’s financial position, results of operations, or cash flows.

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” 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 2007 and 2006:


	Years Ended March 31,
	2007			2006
Asset retirement obligation at beginning of period	$	1,408,000		$	1,263,000
Liabilities settled during the period		(57,000	)		(61,000	)
New obligations for wells drilled and completed		—			29,000
Accretion of asset retirement obligation		108,000			74,000
Revisions to estimates		512,000			103,000


Asset retirement obligation at end of period	$	1,971,000		$	1,408,000

Current liability	$	169,000		$	36,000
Long-term liability		1,802,000			1,372,000


Asset retirement obligation at end of each period	$	1,971,000		$	1,408,000

The asset retirement expense recorded in years ended March 31, 2007 and 2006 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.

3. Other Current Assets

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


	2007		2006
Lease and well equipment inventory	$	159,000	$	161,000
Drilling and completion cost prepayments		50,000		118,000
Prepaid insurance premiums		47,000		12,000
Other current assets		6,000		6,000


Total other current assets	$	262,000	$	297,000

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. The 2006 balance reflects cash advances for future completion work on two North Dakota wells while the 2007 balance corresponds to the unused portion of cash advances on one North Dakota re-completion and on the Table Top Unit #1 well in the Company’s Christmas Meadows prospect.

4. Other Non-Current Assets

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


	2007		2006
Lease and well equipment inventory	$	220,000	$	149,000
Office and support equipment, net		74,000		54,000
Plugging bonds		69,000		69,000


Total other non-current assets	$	363,000	$	272,000

This lease and well equipment inventory, unlike the equipment inventory in Other Current Assets that is held for re-sale, is intended for use on leases that 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 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. Two other amendments include an interest rate reduction from prime plus two percent (2.00%) to prime plus one-quarter of one percent (0.25%) and the addition of an Unused Commitment fee equal to one-half of one percent (0.50%) per annum on the difference between the outstanding balance and the borrowing base amount.

Effective December 31, 2006 the loan agreement was amended again to extend the maturity date of the credit agreement from December 31, 2007 to December 31, 2008. The next borrowing base review is scheduled for July 2007.

Under its credit facility, the Company must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. With the December 31, 2006 amendment, the covenant requiring Basic to maintain a net worth of at least $1,750,000 was replaced with a covenant requiring Basic to maintain a debt-to-equity ratio less than one. Another covenant obligates the Company 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, 2007.

This credit line is collateralized by a significant portion of the Company’s oil and gas properties and production. The interest rate at both March 31, 2007 and 2006 was the prime rate plus 0.25%. Basic’s effective annual interest rate was 8.50% and 8.00% at March 31, 2007 and 2006, respectively.

During both 2007 and 2006 Basic utilized its credit facility to fund portions of its drilling and development program and incurred interest charges of $6,000 and $7,000, respectively. As of March 31, 2007 and 2006 the outstanding balance on the line of credit was $0 and $445,000, respectively. If necessary, the Company may borrow funds to reduce payables, finance re-completion 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 2007 and 2006 and the Company is committed for $33,000 for fiscal year ending March 31, 2008. Prior to expiration of the current lease term, Basic will evaluate the Denver real estate market and the various available options before deciding on where to lease office space after February 2008.

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. During the Plan’s existence, a total of 665,000 options were granted; of this amount, 50,000 options expired unexercised, 425,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share, and 190,000 options remain unexercised as of March 31, 2007 (see tables below).

Current option holders may exercise their options at prices ranging from $0.0325 to $0.1325 per share (which was the market value at the date of grant) over a period not to exceed ten years from the grant 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, 2007 and 2006 and changes during the years ending on those dates is presented below:


	2007						2006
				Weighted						Weighted
				Average						Average
				Exercise						Exercise
	Shares			Price			Shares			Price
Outstanding, beginning of year		365,000		$	0.1023			490,000		$	0.0954

Granted		—			—			—			—
Cancelled		—			—			—			—
Exercised		(175,000	)		(0.1117	)		(125,000	)		(0.0755	)


Outstanding, end of year		190,000		$	0.0936			365,000		$	0.1023


Options exercisable, end of year		190,000		$	0.0936			365,000		$	0.1023


Weighted average fair value of options granted during the year	$	—	$	—

The 175,000 non-qualified options exercised during 2007 had an intrinsic value of $309,700 at the time of exercise.

The following tables provide a summary of the stock options outstanding and exercisable at March 31, 2007:


Options Outstanding
					Weighted
					Average		Weighted
	Range of		Number		Remaining		Average
	Exercise		Outstanding		Contractual		Exercise
	Prices		at 3/31/07		Life		Price
	$	0.0325		25,000	1.33 years		$	0.0325
		0.0420		25,000		2.33		0.0420
		0.0900		25,000		0.33		0.0900
		0.1150		90,000		0.67		0.1150
		0.1325		25,000		3.33		0.1325


	$	0.0325-0.1325		190,000	1.28 years		$	0.0936


Options Exercisable
			Weighted
	Number		Average		Intrinsic
	Exercisable		Exercise		Value		Expiration
	at 3/31/07		Price		at 3/31/07		Date
		25,000	$	0.0325	$	39,000		7/25/08
		25,000		0.0420		40,000		7/25/09
		25,000		0.0900		40,000		7/25/07
		90,000		0.1150		136,000		12/5/07
		25,000		0.1325		37,000		7/26/10


		190,000	$	0.0936	$	292,000

Since all options are fully vested, the Company will have no stock-based compensation expense in future periods unless additional options are granted.

8. Major Customers

Purchasers of 10% or more of Basic’s oil and gas production for 2007 and 2006 are as follows:


	2007			2006
Plains Marketing LP		22	%		15	%
Murphy Oil USA, Inc.		20	%		25	%
Valero Marketing & Supply Company		18	%		17	%

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

A reconciliation between the income tax provision at the statutory rate on income taxes and the income tax provision at March 31, 2007 and 2006 is as follows:


	2007			2006
Federal income tax provision at statutory rates	$	1,161,000		$	993,000
State income tax		106,000			87,000
Change in valuation allowance		(359,000	)		(819,000	)
Other		(1,000	)		(248,000	)


Income tax expense	$	907,000		$	13,000

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.

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


	For the Years Ended March 31,
	2007			2006
Allowance for doubtful accounts	$	26,000		$	26,000
Asset retirement obligation		731,000			537,000
Other accruals		98,000			47,000
Statutory depletion carry-forward		1,244,000			1,897,000


Total gross deferred tax assets		2,099,000			2,507,000
Valuation allowance		—			(359,000	)


Net deferred tax asset		2,099,000			2,148,000
Deferred tax liability – Depreciation, depletion and intangible drilling costs		(2,680,000	)		(2,148,000	)


Net deferred tax liability	$	(581,000	)	$	—

As of March 31, 2007 the Company had fully utilized it net operating loss carry-forward 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 2007 and 2006 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, 2007 Mr. Singleton had a net credit balance of approximately $12,000. This was due to his share of proceeds from the sale of well production equipment exceeding the amount due from him for his share of operating expenses. At March, 31 2006 the Company had an approximate $3,000 receivable from Mr. Singleton for his share of operating expenses. Also at March 31, 2007 and 2006, the Company had approximate $500 and $3,000 payables to him, respectively, for his share of net revenue from these wells.

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 2007 and 2006, Basic contributed approximately $12,000 and $14,000, 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, 2007 and 2006 are as follows:


	2007			2006
Proved property	$	27,686,000		$	24,257,000
Unproved property		1,199,000			2,881,000


		28,885,000			27,138,000
Accumulated depreciation and depletion		(17,842,000	)		(17,250,000	)


Net capitalized oil and gas property	$	11,043,000		$	9,888,000

Costs directly associated with the acquisition and evaluation of unproved property are excluded from the full cost pool depreciation and depletion computation until the properties can be classified as proved. The following table shows, by category and date incurred, the oil and gas property costs applicable to unproved property that were excluded from the depreciation and depletion computation at March 31, 2007:


							Total
Costs Incurred During	Exploration		Development		Acquisition		Unproved
Year Ended	Costs		Costs		Costs		Property
March 31, 2007	$	308,000	$	104,000	$	—	$	412,000
March 31, 2006		428,000		335,000		—		763,000
March 31, 2005		24,000		—		—		24,000


	$	760,000	$	439,000	$	—	$	1,199,000

Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2007 and 2006 are summarized as follows:


	For the Years Ended March 31,
	2007		2006
Development costs	$	1,017,000	$	2,881,000
Exploration costs		686,000		1,394,000
Acquisitions:
Proved		—		—
Unproved		—		—


Total	$	1,703,000	$	4,275,000

13. Unaudited Oil and Gas Reserves Information

At March 31, 2007 and 2006, 92% and 93%, respectively, of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company. The remaining 8 and 7 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 98% of both the Company’s oil and gas production 2007. The Company has elected not to incur the additional expense of evaluating those properties that contributed the remaining 2% of both oil and gas production for inclusion in its estimated oil and gas reserves.

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

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, 2005		1,056,000			870,000

Revisions of previous estimates		(59,000	)		152,000
Extensions and discoveries		55,000			89,000
Sales of reserves in place		—			—
Improved recovery		—			—
Purchase of reserves		—			—
Production		(100,000	)		(141,000	)


Proved developed reserves at March 31, 2006		952,000			970,000

Revisions of previous estimates		92,000			5,000
Extensions and discoveries		55,000			319,000
Sales of reserves in place		—			—
Improved recovery		—			—
Purchase of reserves		—			—
Production		(104,000	)		(156,000	)


Proved developed reserves at March 31, 2007		995,000			1,138,000

All of the Company’s oil and gas reserves at March 31, 2007 and 2006 are classified as Proved Developed, Producing.

The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to 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, 2007 and 2006. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

Standardized Measure of Estimated Discounted Future Net Cash Flows


	At March 31,
	2007			2006
Future cash inflows	$	67,502,000		$	64,022,000
Future cash outflows:
Production cost		(33,909,000	)		(29,618,000	)
Development cost		—			—
Future income taxes		(8,070,000	)		(8,142,000	)


Future net cash flows		25,523,000			26,262,000
Adjustment to discount future annual net cash flows at 10%		(10,899,000	)		(11,230,000	)

Standardized measure of discounted future net cash flows	$	14,624,000		$	15,032,000

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

Changes in Standardized Measure of Estimated Discounted Net Cash Flows


	Years Ended March 31,
	2007			2006
Standardized measure, beginning of period	$	15,032,000		$	14,819,000
Sales of oil and gas, net of production cost		(4,707,000	)		(4,031,000	)
Net change in sales prices, net of production cost		(1,300,000	)		768,000
Discoveries, extensions and improved recoveries, net of future development cost		2,828,000			2,294,000
Change in future development costs		—			4,000
Development costs incurred during the period that reduced future development cost		—			—
Purchase of reserves		—			—
Sales of reserves in place		—			—
Revisions of quantity estimates		1,404,000			(559,000	)
Accretion of discount		1,874,000			1,948,000
Net change in income taxes		(317,000	)		957,000
Changes in rates of production and other		(190,000	)		(1,168,000	)


Standardized measure, end of period	$	14,624,000		$	15,032,000

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, 2007 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.

ITEM 8B
OTHER INFORMATION

There is no information required to be disclosed on Form 8-K during the fourth quarter of the year ended March 31, 2007 that has not been reported.

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 2007 Proxy Statement, which is incorporated herein by reference.

ITEM 10
EXECUTIVE COMPENSATION

Information concerning this item will be in Basic’s 2007 Proxy Statement, which is incorporated herein by reference.

ITEM 11
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT

Information concerning this item will be in Basic’s 2007 Proxy Statement, which is incorporated herein by reference.

ITEM 12
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information concerning this item will be in Basic’s 2007 Proxy Statement, which is incorporated herein by reference.

ITEM 13
EXHIBITS AND REPORTS ON FORM 8-K

Exhibits


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

ITEM 14
PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information concerning this item will be in Basic’s 2007 Proxy Statement, which is incorporated herein by reference.

Exhibit Index

Exhibits


Exhibit No.		Document
3i¹		Restated Certificate of Incorporation included in Basic’s Form 10-K for the year ended March 31, 1981

3i¹		By-laws included in Basic’s Form S-1 filed October 24, 1980

3i¹		Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996

10(i)a¹		Loan Agreement between The Bank of Cherry Creek and Basic, dated March 4, 2002

10(i)a¹		Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.

10(i)a		Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated December 31, 2006

10(ii)¹		Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985

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.


	Page
Part I:
Item 1. Description of Business		3
Item 2. Description of Property		10
Item 3. Legal Proceedings		12
Item 4. Submission of Matters to a Vote of Security Holders		13

Part II:
Item 5. Market for Common Equity and Related Stockholder Matters		14
Item 6. Management’s Discussion and Analysis and Plan of Operation		14
Item 7. Consolidated Financial Statements		22
Item 8. Changes in and Disagreements with Accountants On Accounting and Financial Disclosure		39
Item 8A. Controls and Procedures		39
Item 8B. Other Information		40

Part III:
Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance With Section 16(a) of the Exchange Act		40
Item 10. Executive Compensation		40
Item 11. Security Ownership of Certain Beneficial Owners and Management		40
Item 12. Certain Relationships and Related Transactions		40
Item 13. Exhibits and Reports on Form 8-K		41
Item 14. Principal Accountant Fees and Services		41
Signatures		42
Amended Loan Agreement
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906


Director	For		Against		Abstain
David Flake		13,690,002		—		109,229
Richard Rodgers		13,690,602		—		108,629
Ray Singleton		13,690,002		—		109,229


		Date

/s/ Ray Singleton		June 28, 2007


Ray Singleton, President

/s/ David Flake		June 28, 2007


David Flake, Chief Financial Officer and
Principal Accounting Officer


Name and Capacity		Date

/s/ David Flake		June 28, 2007


David Flake, Director

/s/ Monroe W. Robertson		June 28, 2007


Monroe W. Robertson, Director and
Audit Committee Chairman

/s/ Richard K. Rodgers		June 28, 2007


Richard K. Rodgers, Director and
Compensation Committee Chairman

/s/ Ray Singleton		June 28, 2007


Ray Singleton, Director


	Page
Report of Independent Registered Public Accounting Firm – Hein & Associates LLP		22
Consolidated Balance Sheets		23-24
Consolidated Statements of Operations		25
Consolidated Statements of Shareholders’ Equity		26
Consolidated Statements of Cash Flows		27
Notes to Consolidated Financial Statements		28-39


					Additional
	Common stock				paid-in		Treasury stock						Accumulated
	Shares		Par value		capital		Shares			Amount			deficit
Balance, April 1, 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	)

Stock options exercised		175,000		—		20,000		—			—			—

Net income		—		—		—		—			—			2,500,000


Balance, March 31, 2007		17,304,752	$	17,000	$	22,730,000		(349,265	)	$	(23,000	)	$	(11,644,000	)