Form 10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the Fiscal Year Ended March 31, 2009


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

Commission file number: 0-7914

BASIC EARTH SCIENCE SYSTEMS, INC.

633 17^th Street, Suite 1645
Denver, Colorado 80202-3625
Telephone (303) 296-3076


Incorporated in Delaware		IRS ID# 84-0592823

Securities registered under Section 12(b) of the Act: NONE
Securities registered under Section 12(g) of the Act: Common Stock, $.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not 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-K or any amendment to this Form 10-K. þ

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


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

Indicate by check mark whether the registrant 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: $9,086,000

As of June 18, 2009, 17,505,727 shares of the registrant’s common stock were outstanding, and the aggregate market value of such common stock held by non-affiliates was approximately $21,831,981 as of the registrant’s most recent second fiscal quarter end.

FORWARD-LOOKING STATEMENTS

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

•

our strategies, either existing or anticipated;

•

our future financial position, including anticipated liquidity, including the amount of and our ability to make debt service payments should we utilize some or all of our available borrowing capacity;

•

amounts and nature of future capital expenditures;

•

acquisitions and other business opportunities;

•

operating costs and other expenses;

•

wells expected to be drilled;

•

asset retirement obligations; and

•

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

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

•		oil and natural gas prices;

•		our ability to replace oil and natural gas reserves;

•		loss of senior management or technical personnel;

•		inaccuracy in reserve estimates and expected production rates;

•		exploitation, development and exploration results;

•		costs related to asset retirement obligations;

•		a lack of available capital and financing;

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

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

•		general economic, market or business conditions;

•		factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment, permitting issues, workovers, and weather;

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

•		environmental liabilities;

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

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

•		risk factors discussed in this report and other factors, many of which are beyond our control.

Furthermore, forward-looking statements are made based on our current assessment of the exploratory and development merits of the particular property in light of the geological information available at the time and based on our relative interest in the property and our estimate of our share of the exploration and development cost. Subsequently obtained information concerning the merits of any property, as well as changes in estimated exploration and development costs and ownership interest, may result in revisions to our expectations and intentions and, thus, we may alter our plans regarding these exploration and development activities.

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

Part I

ITEM 1
DESCRIPTION OF BUSINESS

Overview

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

Strategy

Our primary focus is in the Montana and North Dakota portions of the Williston basin. Historically, and in the future, this oil rich basin has been, and will continue to be, allocated the majority of our capital expenditure budget. We have been involved in the Williston basin since the early 1980’s and only in south Texas does the Company have a longer history. As such, we have a significant understanding of, and exposure to, both geology and operations in the area. However, both the Williston basin and our south Texas waterfloods are primarily oil producing properties. While not our primary focus, efforts in other areas, notably, Colorado and on-shore portions of the Gulf Coast, are undertaken to increase our exposure to natural gas projects.

The three components of our growth strategy are:

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

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

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

We anticipate emphasizing acquisitions over drilling in the coming year. While we will be drilling wells (primarily to protect expiring leases and maintain our interests under exploration agreements), we are not expecting our partners to drill at current commodity prices. Finally, we will be focusing on reducing our operating costs as rigs and vendor services become more available.

Areas of Focus

Williston Basin. The Williston basin continues to be our primary area of focus, both in terms of cash flow from existing properties and future expenditures. In the coming year, we expect to increase our efforts to acquire properties in the Williston basin while we continue to exploit ongoing drilling prospects. From a drilling perspective, we have two areas within the Williston basin where we expect drilling operations to continue during the current fiscal year, albeit on a more cautious pace, until commodity prices improve. These areas are our on-going Banks prospect in McKenzie County, North Dakota and our South Flat Lake prospect in Sheridan County, Montana. We caution that the following expectations may be altered by subsequent events or other, more attractive opportunities that may present themselves in the future.

Banks Prospect — McKenzie County, North Dakota. In the fall of 2008, we disclosed that we farmed out our interest in this prospect to Panther Energy Company, LLC (Panther), while retaining a 6.5% working interest. Panther has drilled and completed the two wells they were required to drill under the agreement, and have stated that they will curtail drilling until oil prices are in the $75 per barrel range.

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

Other Areas

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

Denver-Julesberg Basin — Weld County, Colorado. Previously, we disclosed our plans to drill sixteen down-spaced wells on the Antenna Federal property in Weld County, Colorado. As of March 31, 2009, all sixteen new wells had been drilled, completed and are on production. Essentially all development work on this effort has been finalized. We have a 2% to 52.5% revenue interest in Codell/Niobrara production and a 13.125% to 52.5% revenue interest in J-Sand production. The working and revenue interest percentage for each individual well is different and is determined by the specific bottom-hole location of that respective well. In addition, the respective working and revenue interests of the Codell/Niobrara and J-Sand formations may be different in a specific well. These respective interests are also determined by the specific bottom-hole location of that respective well and the spacing unit attributable to that well. However, all new wells currently produce only from the Codell/Niobrara formation. Kerr-McGee Oil & Gas Onshore, LP is the operator of the project.

Christmas Meadows Prospect — Summit County, Utah. In fiscal 2007, we participated with Double Eagle Petroleum Company (“Double Eagle”) in one of the more exciting, true wildcat projects in the Rocky Mountain region, Christmas Meadows. Christmas Meadows is a structural dome in the southwest corner of the prolific Green River Basin, in Summit County, Utah. The dome is overlain by the Wyoming Overthrust Belt and the North Flank Thrust of the Uinta Mountains. The Table Top Unit is a federal unit, which incorporates the Christmas Meadows structural dome and surrounding acreage. During the first quarter of 2007, we drilled Unit test well, the Table Top Unit #1, which reached the originally planned depth of 15,760 feet. The drill cuttings did not reveal reservoir rocks (due to either insufficient hydraulics to bring those cuttings to surface undamaged and intact or because they did not exist). Operations were suspended to assess alternative approaches to completing the project. Having met the governmental permitting obligation for the Unit test well, the expiration dates of the leases were extended. The Table Top Unit, as originally formed, was dissolved and incorporated into a new unit called the Main Fork Unit. As a result of these actions, the time-frame for the expiration of the majority of the leases has been extended until at least August 2009. We are in the process of evaluating potential alternatives, including drilling or farming out the drilling of the Table Top Unit #1 to drill deeper to the Nugget Sandstone at approximately 18,000 feet. Double Eagle has disclosed that it is in discussions with several larger or major companies to take over this venture and deepen this wellbore down to the Nugget formation. At this time, no agreement has been executed, and there can be no assurances that one will be. If no agreement is reached, this leasehold may expire of its own terms and we, Double Eagle and our partners will be required to plug this well and reclaim the access road. We have a 1.5% interest in all future operations in this wellbore and in any future operations on the Christmas Meadows prospect.

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

Contemplated Activities

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

We may alter or vary, all or part of, these contemplated activities based upon changes in circumstances, including, but not limited to unforeseen opportunities, inability to negotiate favorable acquisitions, farmouts, joint ventures or loan terms, commodity prices, lack of cash flow, lack of funding and/or other events which we are not able to anticipate.

Segment Information and Major Customers

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

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

Competition

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

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

Regulations

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

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

Risk Factors

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

We believe that substantially all of our domestic oil produced can be readily sold at prevailing market prices adjusted for regional differentials that reflect location and grade. For March 2009, that price differential ranged from $1.50 to $12.35 below the U.S. crude spot price.

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

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

Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating the future recovery of underground accumulations of oil and natural gas. 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, 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; 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 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-K, should not be construed as the current market value of the estimated oil and gas attributable to our properties. The timing of actual future net cash flows from proved reserves, and thus their actual present value, will be affected by the timing of both the production and incidence of expenses in connection with both extraction costs and development costs. In addition, the 10% discount factor, which is required to be used for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect at the time of calculation.

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

Operating hazards. The oil and gas business involves certain operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could result in substantial losses. In addition, we may be liable for environmental damage caused by previous owners of properties purchased or leased by us. As a result, substantial liabilities to third parties or governmental agencies may be incurred, the payment of which could reduce or eliminate the funds available for acquisitions, development and exploration or result in losses to the Company. We maintain insurance coverage that we believe is customary in the industry.

Other

The oil and gas business is not generally seasonal in nature, although unusual weather extremes for extended periods may increase or decrease demand for oil and natural gas products temporarily. Additionally, catastrophic events, such as hurricanes or other supply disruptions, may also temporarily increase the demand for oil and gas supplies. Such events and their impacts on oil and gas commodity prices may cause fluctuations in quarterly or annual revenue and earnings. Also, because of the location of many of our properties in Montana and North Dakota, severe weather conditions, especially in the winter months, could have a material adverse effect on our operations and cash flow. Other risk factors include changes in regulations and competition. Refer to Competition and Regulations under Item 1. “Description of Business.”

At March 31, 2009, we had nine full-time and two part-time employees. At our subsidiary’s field office in Bruni, Texas, located forty-five miles east, southeast of Laredo, Texas, we have five field laborers who are employees. In addition, we have eleven contract field workers on a part-time retainer basis. We believe our employee and contractor relations are good.

ITEM 1B
UNRESOLVED STAFF COMMENTS

None.

ITEM 2
DESCRIPTION OF PROPERTY

Producing Properties: Location and Impact

At March 31, 2009, we owned a working interest in 94 producing oil wells and 36 producing gas wells. We currently operate 54 of these wells in five states: North Dakota, Montana, Colorado, Texas and Wyoming. These operated wells contributed approximately 67% of both our total liquid hydrocarbon sales and total natural gas sales in fiscal 2009. Virtually all of our property and production are pledged to secure any use of our bank line of credit. Refer to Credit Line under Item 7. “Management’s Discussion and Analysis,” for further information.

Producing Property


	Gross Wells				Net Wells
	Oil		Gas		Oil		Gas
Colorado		—		34		—		7.35
Louisiana		1		1		0.01		0.10
Montana		20		—		9.77		—
North Dakota		49		—		9.43		—
Texas		23		1		20.66		0.11
Wyoming		1		—		0.47		—


Total		94		36		40.34		7.56

Production

Specific production data relative to our oil and gas producing properties can be found in the Selected Financial Information table in Item 7. “Management’s Discussion and Analysis and Plan of Operation.”

Reserves

At March 31, 2009, our estimated proved developed and undeveloped oil and gas reserves in barrels of oil equivalent (BOE) was 794,000, a 35.4% decrease from the prior year’s estimated proved developed oil and gas reserves of 1,229,000 BOE. This decrease was primarily caused by a 51.1% reduction in the price of oil from $101.58 at March 31, 2008 to $49.66 at March 31, 2009.

In addition, due to this decrease in oil and gas prices, our standardized measure of discounted future net cash flows was $7,199,000, a 71.2% decrease from the prior year’s standardized measure of discounted future net cash flows of $24,960,000. Further discussion of our standardized measure of discounted future net cash flows can be found in Note 12 to the Consolidated Financial Statements.

Geographically, our reserves are located in three primary areas: the Williston basin in North Dakota and Montana, the Denver-Julesburg (D-J) basin in Colorado and on-shore south Texas. The following table summarizes the estimated proved developed oil and gas reserves divided between operated and non-operated properties for these three areas as of March 31, 2009:


	Net Oil		Net Gas
	(Bbls)		(Mcf)		BOE		%

Williston Basin
Operated		105,000		53,000		114,000		14.4	%
Non-Operated		221,000		124,000		241,000		30.3	%

		326,000		177,000		355,000		44.7	%

South Texas/Onshore Gulf Coast
Operated		250,000		2,000		251,000		31.6	%
Non-Operated		—		155,000		26,000		3.3	%

		250,000		157,000		277,000		34.9	%

D-J Basin
Operated		16,000		293,000		65,000		8.2	%
Non-Operated		46,000		309,000		97,000		12.2	%

		62,000		602,000		162,000		20.4	%

Total		638,000		936,000		794,000		100	%

Leasehold Acreage

We lease the rights to explore for and produce oil and gas from mineral owners. Leases (quantified in acres) expire after their primary term unless oil or gas production is established. Prior to establishing production, leases are generally considered undeveloped. After production is established, leases are considered developed or “held-by-production.” Our acreage is comprised of developed and undeveloped acreage. As we have shifted to a growth strategy that is more focused on adding reserves through exploration and development drilling, we have begun to acquire various developed and undeveloped leasehold interests.


	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Colorado		640		384		—		—
Louisiana		687		51		—		—
Montana		6,330		3,126		5,662		3,127
North Dakota		14,373		2,929		26,506		4,623
Texas		3,080		2,486		—		—
Utah		—		—		35,945		719
Wyoming		1,555		329		40		1


Total		26,665		9,305		68,153		8,470

Field Service Equipment

At March 31, 2009, one of our subsidiaries, Basic Petroleum Services, Inc. located in Bruni, Texas, owned a trailer house/field office, a shallow pulling rig, a large winch truck, a skid-mounted cementing unit, four pickup trucks and various ancillary service vehicles. None of the vehicles are encumbered.

Office Lease

We currently lease approximately 4,000 square feet of office space in downtown Denver, Colorado from an independent third party for approximately $5,685 per month escalating at a rate of approximately $170 at the end of each year. The lease term is for a five-year period ending April 30, 2013. For additional information see Note 7 to the Consolidated Financial Statements.

ITEM 3
LEGAL PROCEEDINGS

None.

ITEM 4
SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS

There were no matters submitted during the fourth quarter of the fiscal year covered by this report to a vote of securities holders.

Part II

ITEM 5
MARKET FOR COMMON EQUITY,
RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES

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


	High		Low

Year Ended March 31, 2008
First Quarter	$	1.64	$	1.30
Second Quarter		1.45		0.95
Third Quarter		1.23		1.01
Fourth Quarter		1.12		0.89

Year Ended March 31, 2009
First Quarter	$	3.04	$	1.09
Second Quarter		2.31		1.21
Third Quarter		1.30		0.51
Fourth Quarter		1.08		0.51

The closing bid price on June 17, 2009 was $0.81. 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, 2009, we had approximately 2,031 shareholders of record. We have never paid a cash dividend on our common stock. Any future dividend on common stock will be at the discretion of the Board of Directors and will be dependent upon the Company’s earnings, financial condition and other factors. Our Board of Directors presently has no plans to pay any dividends in the foreseeable future.

Purchases of Equity Securities

The following table summarizes stock repurchase activity for the quarters ended December 31, 2008
and March 31, 2009:

Number of

Maximum

Shares

Shares that

Total

Purchased

May Yet be

Number of

Average

as Part of a

Purchased

Shares

Price Paid

Publicly Announced

under

Purchased (1)

Per Share

Plan (1)

the Plan (1)

Quarter ended December 31, 2008

21,600

0.67

21,600

478,400

Quarter ended March 31, 2009

8,600

0.64

8,600

469,800

Total

30,200


(1)		In October 2008, the Company’s Board of Directors authorized a stock buyback program for the Company to repurchase up to 500,000 shares of its common stock. The program does not have a specified expiration date, it does not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time. During the year ended March 31, 2009, 30,200 shares (rounded to 31,000 in the Statement of Stockholder’s Equity) were repurchased under the stock buyback program and 469,800 shares remain available for future repurchase.

ITEM 6
SELECTED FINANCIAL DATA

Smaller reporting companies are not required to provide the information required by this Item.

ITEM 7
MANAGEMENT’S DISCUSSION AND ANALYSIS
AND PLAN OF OPERATION

Liquidity Outlook

Our primary source of funding is the net cash flow from the sale of our oil and gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and then sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. Assuming oil prices do not decline significantly from current levels, we believe the cash generated from operations will provide sufficient working capital for us to meet our existing and normal recurring obligations as they become due. In addition, as mentioned in the “Debt” section below, we have an available borrowing capacity of $4,000,000 as of June 18, 2009.

Capital Structure and Liquidity

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

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

Credit Line. Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Effective January 3, 2006 we amended the existing loan agreement to increase the line of credit amount from $1,000,000 to $20,000,000 with a concurrent borrowing base increase from $1,000,000 to $4,000,000. Effective December 31, 2008 the loan agreement was amended again to extend the maturity date of the credit agreement to December 31, 2010.

During the years ended March 31, 2009 and 2008, we utilized none of our credit facility. Our effective annual interest rate is 6.50% or prime plus 0.25%, whichever is greater. On June 18, 2009 we had no outstanding principal balance on the line of credit, with the entire $4,000,000 available for borrowing. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities we cannot envision at this time. See Note 6 to the Consolidated Financial Statements for a more detailed discussion of our bank credit facility.

Hedging. During 2009 and 2008, we did not participate in any hedging activities, nor did we have any open futures or option contracts. Additional information concerning our hedging activities appears in Note 1 to the Consolidated Financial Statements.

Working Capital. At March 31, 2009, we had a working capital surplus of $5,045,000 (a current ratio of 4.62:1) compared to a working capital surplus at March 31, 2008 of $3,168,000 (a current ratio of 1.79:1).

Cash Flow. As mentioned above, our primary source of funding is the cash flow from our operations. Cash provided by operating activities decreased 20.4% from $3,609,000 in 2008 to $2,872,000 in 2009. Net cash used in investing activities increased 654.4% from $575,000 in 2008 to $4,338,000 in 2009, which relates primarily to our drilling and completion activities during the year.

We have not borrowed on our line of credit since June 2006. Cash provided by financing activities was $14,000 in 2008 from the proceeds of a stock option exercise, while cash used in financing activities was $17,000 in 2009, for the proceeds from the exercise of the remaining stock options outstanding, and the purchase of treasury shares.

Capital Expenditures. During 2009 our capital expenditures were primarily focused on properties in the Williston Basin of Montana and North Dakota and in the DJ Basin of Colorado. On an accrual basis, total capital expenditures during 2009 for oil and gas property and equipment and various leasehold interests were $2,177,000. Of these expenditures, $1,607,000 (74%) are attributable to the Williston Basin for the acquisition, drilling, completion and leasehold costs of wells in this area, while the Antenna Federal property in the DJ Basin of Colorado received $551,000 (25%) of these expenditures. These projects were funded entirely with internally generated cash flow. See also the Areas of Focus and Company Developments sections of Part 1 of this report for further discussion related to our exploration and development activities.

We are continually evaluating exploration, development and acquisition opportunities in an effort to grow our oil and gas reserves. At present cash flow levels and available borrowing capacity, we expect to have sufficient funds available for our share of any additional acreage, seismic and/or drilling cost requirements that might arise from these opportunities. However, we may alter or vary all or part of these planned capital expenditures based upon changes in circumstances, unforeseen opportunities, inability to negotiate favorable acquisition, farmout or joint venture terms, lack of cash flow, lack of additional funding, if necessary, and/or other events which we are not able to anticipate.

Divestitures/Abandonments. We plugged two wells during 2009 and incurred some additional costs pertaining to the abandonment of wells that were plugged in prior periods.

Impact of Inflation. We deal primarily in US dollars. 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.

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

Results of Operations

Fiscal 2009 Compared with Fiscal 2008

Overview. Net income for the year ended March 31, 2009 was $578,000 compared to net income of $1,763,000 for the year ended March 31, 2008, a 67.2% decrease. Earnings for 2009 would have increased if not for an impairment to our oil and gas property, as well as an increase in depletion expense. Production expenses and general and administrative also increased during the year.

Revenues. Oil and gas sales revenue increased $1,576,000 (21.3%) in 2009 over 2008 as a result of overall higher average oil and gas prices and increased gas production. Gas sales revenue alone increased $918,000 (137.6%) in 2009 from 2008, while oil sales revenue increased $658,000 (9.8%).

Volumes and Prices. Oil sales volumes increased 3.6% from 89,400 barrels in 2008 to 92,657 barrels in 2009, while the average price per barrel increased 5.9% from $75.47 in 2008 to $79.93 in 2009. Gas sales volume increased 61.5% from 108.6 million cubic feet (MMcf) in 2008 to 175.4 MMcf in 2009. The average price per Mcf also increased 47.4%, from $6.13 in 2008 to $9.04 in 2009. The production increase in gas in 2009 was primarily due to the Antenna Federal wells being temporarily shut in during 2008 for the rebuilding of tank batteries and the completion of new Antenna Federal wells during 2009. On an equivalent barrel (BOE) basis, sales increased 13% from 108,000 BOE in 2008 to 122,000 BOE in 2009.

Expenses. Oil and gas production expense increased $454,000 (21.8%) in 2009 over 2008. 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 primarily include downhole repairs and are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their associated costs 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 $367,000 (22.9%) from $1,602,000 in 2008 to $1,969,000 in 2009, which is due in large part to expenses incurred from our new wells in the Williston and DJ Basins, as well as an increase in expenses on the TR Madison Unit and Federal 35-2 in North Dakota. Workover expense increased $87,000 (18%) from $483,000 in 2008 to $570,000 in 2009 related to workovers of the Whiskey Joe Federal and Beicegal Carson wells in North Dakota. On an equivalent barrel basis, routine lease operating expense increased 8.8% from $14.84 per BOE in 2008 to $16.14 in 2009, while workover expense decreased 4.5% from $4.89 in 2008 to $4.67 per BOE in 2009.

Production taxes, which are a function of sales revenue, increased $23,000 (3.7%) in 2009 over 2008. Production taxes as a percent of oil and gas sales revenue decreased from 8.3% in 2008 to 7.1% in 2009.

The overall lifting cost (oil and gas production expense plus production taxes) per BOE was $26.09 in 2009 compared to $24.86 in 2008. This cost per equivalent barrel is not indicative of all wells, and certain high cost wells could be shut in should oil prices drop below certain levels.

Depreciation, depletion and amortization expense increased $539,000 (78.7%) in 2009 over 2008. This increase was created by a drop in oil and gas prices at year end and the corresponding reduction in recoverable reserves, mathematically accelerating the rate at which actual production creates depletion expense. Depreciation, depletion and amortization expense per BOE increased from $6.34 in 2008 to $10.03 in 2009.

Accretion of asset retirement obligation decreased $16,000 (14%) in 2009 from 2008. This decrease is in part a result of revisions to the estimated lives of some of our wells sharing the same leased acreage. Additional information concerning SFAS No. 143 and related activity during 2009 can be found in Note 5 to the Consolidated Financial Statements.

Impairment of oil and gas properties occurred during the year as a result of the decline in oil and gas prices. Like most companies, we incurred a charge consistent with the results of our “ceiling test” which places a “ceiling” on our capitalized costs, thereby limiting our pooled capital 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 this “ceiling,” we are required to record a write-down to the extent of such excess. This write-down is a non-cash charge to earnings. It reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. Accordingly, during the year ended March 31, 2009, we determined that our capitalized costs exceeded the ceiling test limit and recorded an impairment write-down of $2,694,000, compared to no ceiling test impairment for the year ended March 31, 2008.

General and administrative (G&A) expense increased $631,000 (88.1%) in 2009 over 2008. This increase was primarily due to consulting fees in connection with SEC reporting requirements, bad debt expense, professional fees (legal), increased rent expense, increases in employees and employee compensation and consulting fees in connection with Sarbanes-Oxley implementation and reporting. The percentage of G&A expense that was charged out to operated properties was 14.4% in 2009 compared to 22% in 2008. G&A expense per BOE increased 85.9% from $5.94 in 2008 to $11.04 in 2009. G&A expense as a percentage of total sales revenue also increased from 9.7% in 2008 to 14.8% in 2009.

Other Income/Expense. Due to higher average balances of cash during the prior year, Interest and other income decreased from $152,000 in 2008 to $57,000 in 2009. Interest and other expenses increased from $28,000 in 2008 to $34,000 in 2009.

Income Taxes. In 2009, we recorded income tax expense (benefit) of $(212,000) comprised of a current year income tax provision of $346,000, and a deferred income tax provision (benefit) of $(558,000). This compares to a 2008 income tax expense of $1,525,000. At March 31, 2008, we had a net deferred tax liability of $1,346,000. Our effective income tax rate decreased from 46.38% for 2008 to (56.34)% for 2009. Our effective income tax rate was lower for 2009 primarily due to an increase in estimated deductions for statutory depletion and impairment expense.

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.


	Year Ended
	March 31,
	2009		2008		2007

Sales volume
Oil (barrels)		92,657		89,400		104,200
Gas (mcf)		175,413		108,600		155,800

Revenue
Oil	$	7,406,000	$	6,748,000	$	6,115,000
Gas		1,585,000		667,000		1,014,000

Total revenue		8,991,000		7,415,000		7,129,000

Total production expense¹		3,183,000		2,706,000		2,422,000


Gross profit	$	5,808,000	$	4,709,000	$	4,707,000


Depletion expense	$	1,188,000	$	673,000	$	631,000
General and administrative expense		1,347,000		716,000		546,000

Average sales price²
Oil (per barrel)	$	79.93	$	75.47	$	58.70
Gas (per mcf)	$	9.04	$	6.13	$	6.51

Average per BOE
Production expense^2,3,4	$	26.09	$	19.27	$	18.61
Gross profit^3,4	$	47.61	$	43.96	$	36.17
Depletion expense^3,4	$	10.03	$	5.59	$	4.85
General and administrative expense^3,4	$	11.04	$	5.94	$	4.20


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 full cost pool ceiling limitation

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the actual amounts of assets and liabilities at the date of the financial statements and the actual amounts of revenues and expenses during the reporting period. We base these estimates on assumptions that we understand are reasonable under the circumstances. The estimated results that are produced by this effort will differ under different assumptions or conditions. We understand that these estimates are necessary and that actual results could vary significantly from the estimated amounts for the current and future periods. We understand the following accounting policies and estimates are necessary in the preparation of our consolidated financial statements: the carrying value of our oil and gas property, the accounting for oil and gas reserves, the estimate of our asset retirement obligations and the estimate of our income tax assets and liabilities.

Oil and Gas Property. We utilize the full cost method of accounting for costs related to our oil and gas property. Capitalized costs included in the full cost pool are depleted on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and may result in lower depreciation and depletion in future periods. The write-down can not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.

Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of our oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves attributable to these properties. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Ninety-eight percent of our reported oil and gas reserves at March 31, 2009 are based on estimates prepared by an independent petroleum engineering firm. The remaining two percent of our oil and gas reserves were prepared in-house. See also Note 12 to the Consolidated Financial Statements.

Asset Retirement Obligations. We have significant obligations related to the plugging and abandonment of our oil and gas wells, the removal of equipment and facilities and returning the land to its original condition. SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that we estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in its Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash expenditures and inflation rates. The nature of these estimates requires management to make judgments based on historical experience and future expectations related to timing. We review the estimate of our future asset retirement obligations quarterly. These quarterly reviews may require revisions to these estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. See also Note 5 to the Consolidated Financial Statements.

Off Balance Sheet Transactions, Arrangements or Obligations

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

Recent Accounting Pronouncements

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

ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

Smaller reporting companies are not required to provide the information required by this Item.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders
Basic Earth Science Systems, Inc.
Denver, Colorado

We have audited the accompanying consolidated balance sheet of Basic Earth Science Systems, Inc. and Subsidiaries (the “Company”) as of March 31, 2009, and the related statements of operations, shareholders’ equity, and cash flows for the year then ended March 31, 2009. 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 audit.

We conducted our audit 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Basic Earth Science Systems, Inc. as of March 31, 2009, and the results of its operations and its cash flows for the year ended March 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado
June 17, 2009

REPORT OF PRIOR INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and shareholders
Basic Earth Science Systems, Inc.
Denver, CO

We have audited the consolidated balance sheet of Basic Earth Science Systems, Inc. and subsidiaries, (the “Company”) as of March 31, 2008, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year 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 audit.

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

HEIN & ASSOCIATES LLP

Denver, Colorado
July 11, 2008

Basic Earth Science Systems, Inc.

Consolidated Balance Sheets


	March 31,			March 31,
	2009			2008

Assets
Current assets:
Cash and cash equivalents	$	4,088,000		$	5,571,000
Accounts receivable:
Oil and gas sales		1,611,000			1,110,000
Joint interest and other receivables, net of $71,000 and $50,000 in allowance, respectively		230,000			236,000
Other current assets		508,000			280,000


Total current assets		6,437,000			7,197,000

Oil and gas property, full cost method:
Proved property		32,187,000			29,050,000
Unproved property		1,077,000			2,515,000
Accumulated depletion and impairment		(22,397,000	)		(18,515,000	)


Net oil and gas property		10,867,000			13,050,000


Support equipment and other non-current assets, net of $337,000 and $299,000 in accumulated depreciation, respectively		458,000			443,000


Total non-current assets		11,325,000			13,493,000

Total assets	$	17,762,000		$	20,690,000

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.
Consolidated Balance Sheets


	March 31,			March 31,
	2009			2008

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	64,000		$	1,443,000
Accrued liabilities		1,328,000			2,586,000


Total current liabilities		1,392,000			4,029,000

Long-term liabilities:
Deferred tax liability		2,242,000			2,800,000
Asset retirement obligation		1,558,000			1,877,000


Total long-term liabilities		3,800,000			4,677,000

Total liabilities		5,192,000			8,706,000


Commitments (Note 7)

Shareholders’ Equity:
Preferred stock, $.001 par value, 3,000,000 authorized, and none issued or outstanding		—			—
Common stock, $.001 par value, 32,000,000 shares authorized, and 17,506,000 and 17,466,000 shares issued and outstanding, respectively		18,000			17,000
Additional paid-in capital		22,825,000			22,798,000
Treasury stock (380,000 shares); at cost		(43,000	)		(23,000	)
Accumulated deficit		(10,230,000	)		(10,808,000	)


Total shareholders’ equity		12,570,000			11,984,000

Total liabilities and shareholders’ equity	$	17,762,000		$	20,690,000

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

Consolidated Statements of Operations


	Years Ended
	March 31,
	2009			2008

Revenues:
Oil and gas sales	$	8,991,000		$	7,415,000
Well service and water disposal revenue		95,000			32,000


Total revenues		9,086,000			7,447,000


Expenses:
Oil and gas production		2,539,000			2,085,000
Production tax		644,000			621,000
Well servicing expenses		33,000			27,000
Depreciation and depletion		1,224,000			685,000
Accretion of asset retirement obligation		98,000			114,000
Asset retirement expense		164,000			35,000
Impairment of oil and gas property		2,694,000			—
General and administrative		1,347,000			716,000


Total expenses		8,743,000			4,283,000


Income from operations		343,000			3,164,000


Other Income (Expense):
Interest and other income		57,000			152,000
Interest and other expenses		(34,000	)		(28,000	)


Total other income		23,000			124,000


Income before income taxes		366,000			3,288,000


Current income tax expense		346,000			179,000
Provision for deferred income tax (benefit) expense		(558,000	)		1,346,000


Total income tax (benefit) expense		(212,000	)		1,525,000


Net income	$	578,000		$	1,763,000


Per share amounts:
Basic	$	0.03		$	0.10

Diluted	$	0.03		$	0.10


Weighted average common shares outstanding:
Basic		17,477,216			17,370,256

Diluted		17,477,216			17,480,671

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

Consolidated Statements of Shareholders’ Equity
Years Ended March 31, 2009 and 2008


					Additional
	Common stock				paid-in		Treasury stock						Accumulated
	Shares		Par value		capital		Shares			Amount			deficit			Total

Balance, March 31, 2007		17,301,000	$	17,000	$	22,749,000		(349,000	)	$	(23,000	)	$	(12,571,000	)	$	10,172,000


Purchase of treasury shares		—		—		—		—			—			—			—
Stock options exercised		165,000		—		49,000		—			—			—			49,000
Net income		—		—		—		—			—			1,763,000			1,763,000


Balance, March 31, 2008		17,466,000	$	17,000	$	22,798,000		(349,000	)	$	(23,000	)	$	(10,808,000	)	$	11,984,000


Purchase of treasury shares		—		—		—		(31,000	)		(20,000	)		—			(20,000	)
Shares issued to independent board members		15,000		—		24,000		—			—			—			24,000
Stock options exercised		25,000		1,000		3,000		—			—			—			4,000
Net income		—		—		—		—			—			578,000			578,000


Balance, March 31, 2009		17,506,000	$	18,000	$	22,825,000		(380,000	)	$	(43,000	)	$	(10,230,000	)	$	12,570,000

See accompanying notes to consolidated financial statements.

Basic Earth Science Systems, Inc.

Consolidated Statements of Cash Flows


	Years Ended
	March 31,
	2009			2008

Cash flows from operating activities:
Net income	$	578,000		$	1,763,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		1,224,000			685,000
Deferred tax liability		(558,000	)		1,311,000
Additional paid-in capital associated with deferred tax expense		—			35,000
Accretion of asset retirement obligation		98,000			114,000
Share based compensation		24,000			—
Impairment of Oil and Gas Properties		2,694,000			—
Change in:
Accounts receivable, net		(495,000	)		(85,000	)
Other assets		(287,000	)		(63,000	)
Accounts payable and accrued liabilities		(406,000	)		(158,000	)
Other		—			7,000


Net cash provided by operating activities		2,872,000			3,609,000


Cash flows from investing activities:
Oil and gas property		(4,338,000	)		(587,000	)
Support equipment		—			(16,000	)
Insurance settlements		—			66,000
Proceeds from sale of oil and gas property and equipment		—			14,000
Other		—			(52,000	)


Net cash used in investing activities		(4,338,000	)		(575,000	)


Cash flows from financing activities:
Proceeds from exercise of common stock options		3,000			14,000
Purchase of treasury shares		(20,000	)		—


Net cash (used in) provided by financing activities		(17,000	)		14,000


Cash and cash equivalents:
(Decrease) increase in cash and cash equivalents		(1,483,000	)		3,048,000
Balance, beginning of year		5,571,000			2,523,000


Balance, end of period	$	4,088,000		$	5,571,000


Supplemental disclosure of cash flow information:
Cash paid for interest	$	10,000		$	28,000

Cash paid for income tax	$	517,000		$	171,000


Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	33,000		$	210,000

Additions to oil and gas also included in accrued liabilities	$	43,000		$	2,273,000

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” or “we” or “our” or “us”), was originally organized in July 1969 and had its first public offering in 1980. We are principally engaged in the acquisition, exploitation, development, operation and production of crude oil and natural gas. Our primary areas of operation are the Williston basin in North Dakota and Montana, south Texas and the Denver-Julesburg basin in Colorado.

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

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

Oil and Gas Producing Activity. We follow the full cost method of accounting for our oil and gas activity. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves using current prices and costs discounted at 10 percent plus the lower of cost or fair value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. While we did not incur a ceiling limitation charge for the year ended March 31, 2008, we incurred a ceiling test limitation charge in the amount of $2,694,000 during the year ended March 31, 2009, representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules.

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

All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties we own. Depletion expense per equivalent barrel of production was $10.03 and $6.34 for 2009 and 2008, respectively.

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

Earnings Per Share. Our earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of securities, if any, 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 2009 and 2008:


	Years Ended
	March 31,
	2009		2008
Numerator:
Net income available to common shareholders	$	578,000	$	1,763,000


Denominator:
Denominator for basic earnings per share		17,477,216		17,370,256


Effect of dilutive securities:
Stock options		—		110,415

Denominator for diluted earnings per share		17,477,216		17,480,671

All options issued and outstanding were included in the computation of diluted earnings per share for 2008, and were not applicable for 2009. See Note 8 below for further discussion of our stock options.

Cash and Cash Equivalents. For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, we consider all highly liquid investments with a maturity of ninety days or less when purchased to be cash equivalents. The carrying amount of cash equivalents approximates fair value because of the short-term maturity of those instruments. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash, trade receivables, trade payables and accrued liabilities. The carrying value of cash and cash equivalents, trade receivables, trade payables and accrued liabilities are considered to be representative of their fair market value, due to the short maturity of these instruments.

Hedging Activities. We had no hedging activities in 2009 and 2008. Hedging strategies, or absence of hedging, may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events which we are not able to anticipate.

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 primarily the straight-line method over periods ranging from five to seven years.

Inventory. Inventory, consisting primarily of tubular goods and oil field equipment, is stated at the lower of cost or market, cost being determined by the FIFO method. See also Notes 2 and 3 below.

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

Major Customers and Concentration of Credit Risk. Purchasers of 10% or more of our oil and gas production revenue for 2009 and 2008 are as follows:


	2009			2008

Murphy Oil USA, Inc.		25	%		22	%
Valero Energy		17	%		20	%
Nexen Marketing USA, Inc.		14	%		11	%
Plains Inc.		14	%		15	%
Texon LP		6	%		10	%


Total		76	%		78	%

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

Stock Option Plan. With the issuance of SFAS No. 123(R), Accounting for Share Based Compensation, effective December 2004, we are required to recognize all equity-based compensation, including stock option grants, as stock-based compensation expense in our Consolidated Statements of Operations based on the fair value of the compensation. No options have been granted since July 2003, and the plan expired in July 2005. Therefore, we issued no further stock options in either 2009 or 2008. See Note 8 below for further discussion of the Company’s stock options.

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

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.

Recent Accounting Pronouncements

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

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

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

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

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The adoption of SFAS 162 is not expected to have an impact on the Company’s financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R will significantly change the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, research and development assets and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. SFAS 141R is effective for fiscal years beginning after December 15, 2008. We anticipate adopting the provisions of SFAS 141R beginning April 1, 2009, and do not anticipate it to have a material effect on our financial position, results of operations, or cash flows.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements, An Amendment of ARB No. 51.” SFAS 160 amends ARB 51 to establish accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB 51’s consolidation procedures for consistency with the requirements of SFAS 141R. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The statement shall be applied prospectively as of the beginning of the fiscal year in which the statement is initially adopted. We will adopt the provisions of SFAS 160 beginning April 1, 2009, and do not anticipate it to have a material effect on our financial position, results of operations, or cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, providing companies with an option to report selected financial assets and liabilities at fair value. The Standard’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. Generally accepted accounting principles have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. SFAS 159 helps to mitigate this type of accounting-induced volatility by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with detailed rules for hedge accounting. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of our choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the Company has chosen to use fair value on the face of the balance sheet. The effective date of SFAS 159 for our Company is April 1, 2008. We have adopted the provisions of SFAS 159, and it does not have a material effect on our financial position, results of operations, or cash flows as of March 31, 2009. The adoption of SFAS No. 159 did not have a material effect on our financial condition or results of operations as we did not make any such elections under this fair value option.

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

2. Other Current Assets

Other current assets at March 31, 2009 and 2008 consisted of the following:


	2009		2008

Lease and well equipment inventory	$	170,000	$	154,000
Drilling and completion cost prepayments		149,000		52,000
Prepaid insurance premiums		44,000		58,000
Other current assets		145,000		16,000


Total other current assets	$	508,000	$	280,000

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

Drilling and completion cost prepayments represent cash expenditures advanced by us to outside operators prior to the commencement of drilling and/or completion operations on a well.

3. Other Non-Current Assets

Other non-current assets at March 31, 2009 and 2008 consisted of the following:


	2009		2008

Lease and well equipment inventory	$	261,000	$	250,000
Plugging bonds		60,000		69,000
Other non-current assets		137,000		124,000


Total other non-current assets	$	458,000	$	443,000

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

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

4. Accrued Liabilities

Accrued liabilities at March 31, 2009 and 2008 consisted of the following:


	Years Ended
	March 31,
	2009		2008

Revenue and production taxes payable	$	532,000	$	574,000
Accrued payables		368,000		1,396,000
Accrued compensation		288,000		313,000
Short term asset retirement obligation		140,000		303,000


Total	$	1,328,000	$	2,586,000

5. Asset Retirement Obligation

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

The following table summarizes the activity related to our estimate of future asset retirement obligations for 2009 and 2008:


	Years Ended
	March 31,
	2009			2008

Asset retirement obligation at beginning of period	$	2,179,000		$	1,971,000
Liabilities settled during the period		(168,000	)		(116,000	)
New obligations for wells drilled and completed		33,000			84,000
Accretion of asset retirement obligation		98,000			114,000
Revisions to estimates		(444,000	)		126,000


Asset retirement obligation at end of period	$	1,698,000		$	2,179,000


Current accrued liability	$	140,000		$	302,000
Long-term liability		1,558,000			1,877,000


Asset retirement obligation at end of each period	$	1,698,000		$	2,179,000

Asset retirement expense as recorded in the years ended March 31, 2009 and 2008 represents plugging and abandonment costs in excess of the estimated asset retirement obligation recorded with the adoption of SFAS No. 143. We based our initial estimates on our knowledge and experience plugging wells in earlier years.

6. Credit Line

Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Effective January 3, 2006 we amended the existing loan agreement to increase the line of credit amount from $1,000,000 to $20,000,000 with a concurrent borrowing base increase from $1,000,000 to $4,000,000. Effective December 31, 2008, the loan agreement was amended again to extend the maturity date of the credit agreement from December 31, 2008 to December 31, 2010. The current interest rate is 6.5% or prime plus one-quarter of one percent (0.25%) whichever is greater, and the addition of an unused commitment fee equal to one-half of one percent (0.50%) per annum on the difference between the outstanding balance and the borrowing base amount.

Under the credit facility, we must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. With the December 31, 2008 amendment, the covenant requiring us to maintain a net worth of at least $1,750,000 was replaced with a covenant requiring us to maintain a debt-to-equity ratio less than one. Another covenant obligates us to maintain a current ratio of at least 1:1 inclusive of unused borrowing capacity and exclusive of the current portion of long-term debt. We were in compliance with all covenants at March 31, 2009.

This credit line is collateralized by a significant portion of our oil and gas properties and production, and as of March 31, 2009, there was no outstanding balance on this line of credit. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities that might arise.

7. Commitments

Effective March 1, 2008, we relocated to a new 4,000 square foot office space located in downtown Denver, Colorado. The lease agreement is for a five-year term through April 2013 and currently requires approximately $5,685 per month escalating at a rate of approximately $170 at the end of each year. Office rent expense was approximately $87,000 in 2009 (including building maintenance charges), and $36,000 in 2008. We are committed to a total of $281,000 for the five-year term ending April 1, 2013. Prior to expiration of the lease term, we will evaluate the Denver real estate market and the various available options before deciding on where to lease office space after April 2013.

8. Shareholders’ Equity

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

Stock Option Plan. Effective July 27, 1995, our shareholders approved the 1995 Incentive Stock Option Plan (“the Plan”) authorizing option grants to employees and outside directors to purchase up to 1,000,000 shares of our common stock. The Plan was structured as a 10-year plan and, as such, ended on July 26, 2005. During the Plan’s existence, a total of 665,000 options were granted; of this amount, 50,000 options expired unexercised, 590,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share and the remaining 25,000 options were exercised as of March 31, 2009 (see the table below).

A summary of the status of our stock option plan and outstanding options as of March 31, 2009 and 2008, and changes during the years ending on those dates is presented below:


	2009						2008
				Weighted						Weighted
				Average						Average
				Exercise						Exercise
	Shares			Price			Shares			Price

Options unexercised, beginning of year		25,000		$	0.1325			190,000		$	0.0936

Granted		—			—			—			—
Cancelled		—			—			—			—
Exercised		(25,000	)		(0.1325	)		(165,000	)		(0.0941	)


Options unexercised and exercisable, end of year		—		$	—			25,000		$	0.1325

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

Director Stock Compensation. On March 8, 2007, the Board of Directors adopted a new Director Compensation Plan. In connection with this plan, an annual stock grant equal to $36,000 is awarded to each independent director. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date.

9. Income Tax

Our provision for income taxes comprised of the following:


	For the Years Ended
	March 31,
	2009			2008

Current:
Federal	$	305,000		$	155,000
State		41,000			24,000

Total current		346,000			179,000

Deferred :
Federal		(483,000	)		1,166,000
State		(75,000	)		180,000

Total deferred (benefit)		(558,000	)		1,346,000

Total income tax provision	$	(212,000	)	$	1,525,000

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


	For the Years Ended
	March 31,
	2009			2008

Federal income tax provision at statutory rates	$	124,000		$	1,118,000
State income tax		(18,000	)		164,000
Change in depletion carryforward		—			592,000
Excess percentage depletion		(322,000	)		(346,000	)
Other		4,000			(3,000	)


Income tax expense	$	(212,000	)	$	1,525,000

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


	For the Years Ended
	March 31,
	2009			2008

Allowance for doubtful accounts	$	26,000		$	20,000
Asset retirement obligation		633,000			850,000
Other accruals		(4,000	)		112,000
Statutory depletion carryforward		858,000			1,043,000


Total gross deferred tax assets		1,513,000			2,025,000


Deferred tax liability — Depreciation, depletion and intangible drilling costs		(3,755,000	)		(4,825,000	)


Net deferred tax liability	$	(2,242,000	)	$	(2,800,000	)

As of March 31, 2009, we had fully utilized our net operating loss carry-forward for tax purposes. We have statutory depletion carryforwards of $2,300,000 that do not expire.

The adoption of FIN 48 had no impact on our consolidated financial statements. We are subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are fiscal years 2004 through 2008. We recognize interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2009, we made no provisions for interest or penalties related to uncertain tax positions.

10. Related Party Transactions

It is our policy that officers or directors may assign to us or receive assignments from us in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. It is also our policy that officers or directors and the Company may participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by each other. During 2009 and 2008 none of our officers or directors participated with the Company in any of our oil and gas transactions. In prior years, Ray Singleton, President of the Company, has participated with us in certain acquisitions. With respect to his working interest in the four wells in which he currently participates, at March 31, 2009 the Company had a balance due from Mr. Singleton for less than $1,000 compared to a payable balance due to him of approximately $2,000 at March 31, 2008. This was due to his share of operating expenses exceeding the amount due to him for his share of oil and gas revenue from these wells.

11. Oil and Gas Property

The aggregate amount of capitalized costs related to oil and gas properties and the aggregate amount of related accumulated depreciation and depletion at March 31, 2009 and 2008 are as follows:


	2009			2008

Proved property	$	32,187,000		$	29,050,000
Unproved property		1,077,000			2,515,000


Gross oil and gas property		33,264,000			31,565,000
Accumulated depletion and impairment		(22,397,000	)		(18,515,000	)


Net oil and gas property	$	10,867,000		$	13,050,000

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

Banks Prospect. The Banks Prospect represents approximately 55.3% of total unproved property costs, $596,000, associated with a 13,000 gross acre horizontal Bakken play in McKenzie County, North Dakota. For further information see Areas of Focus of Item 1. “Description of Business.”

Christmas Meadows. The Christmas Meadows prospect consists of approximately 36.8% of total unproved property costs, $396,000, related to 40,000+ acres operated by Double Eagle Petroleum Company (Double Eagle). For further information see Areas of Focus of Item 1. “Description of Business.”

South Flat Lake Prospect. The South Flat Lake prospect represents approximately 5.5% of total unproved property costs, $59,000, associated with a 4,200 gross acres (2,100 net) prospect in northern Sheridan County near the Flat Lake Field. For further information see Areas of Focus of Item 1. “Description of Business.”

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, 2009:


							Total
Costs Incurred During	Exploration		Development		Acquisition		Unproved
Year Ended	Costs		Costs		Costs		Property

March 31, 2009	$	249,000	$	—	$	—	$	249,000
March 31, 2008		29,000		—		—		29,000
March 31, 2007		308,000		—		—		308,000
March 31, 2006		428,000		39,000		—		467,000
March 31, 2005		24,000		—		—		24,000


Total	$	1,038,000	$	39,000	$	—	$	1,077,000

Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2009 and 2008 are summarized as follows:


	For the Years Ended
	March 31,
	2009		2008

Development costs	$	2,177,000	$	2,410,000
Exploration costs		—		40,000
Acquisitions:
Proved		—		250,000
Unproved		—		—


Total	$	2,177,000	$	2,700,000

12. Unaudited Oil and Gas Reserves Information

At March 31, 2009 and 2008, 98% 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 2 and 7 percent of the reserve estimates, respectively, were prepared internally by our management. 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.

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. Proved undeveloped reserves are reserves expected to be recovered through wells yet to be completed.

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 tables:

Proved Reserves


	Oil and
	Natural
	gas			Natural
	liquids			gas
	(Bbls)			(Mcf)

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


Revisions of previous estimates		112,000			(113,000	)
Extensions and discoveries		19,000			203,000
Sales of reserves in place		—			—
Improved recovery		15,000			1,000
Purchase of reserves		22,000			—
Production		(89,000	)		(109,000	)


Proved developed reserves at March 31, 2008		1,074,000			1,120,000


Revisions of previous estimates		(429,000	)		(262,000	)
Extensions and discoveries		86,000			253,000
Sales of reserves in place		—			—
Improved recovery		—			—
Purchase of reserves		—			—
Production		(93,000	)		(175,000	)


Proved developed and undeveloped reserves at March 31, 2009		638,000			936,000

As of March 31, 2009, we have proved reserves related to undeveloped property, whereas for March 31, 2008, all of our oil and gas reserves were classified as Proved Developed, Producing.

The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to our proved oil and gas reserves. Estimated future cash inflows were computed by applying year end (March 31) prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves at March 31, 2009 and 2008. 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


	For the Years Ended
	March 31,
	2009			2008

Future cash inflows	$	31,793,000		$	114,296,000
Future cash outflows:
Production cost		(17,924,000	)		(49,599,000	)
Development cost		(490,000	)		—
Future income taxes		(2,100,000	)		(17,826,000	)


Future net cash flows		11,279,000			46,871,000
Adjustment to discount future annual net cash flows at 10%		(4,080,000	)		(21,911,000	)


Standardized measure of discounted future net cash flows	$	7,199,000		$	24,960,000

The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for 2009 and 2008.

Changes in Standardized Measure of Estimated Discounted Net Cash Flows


	For the Years Ended
	March 31,
	2009			2008

Standardized measure, beginning of period	$	24,960,000		$	14,624,000

Sales of oil and gas, net of production cost		(5,808,000	)		(4,727,000	)
Net change in sales prices, net of production cost		(25,977,000	)		14,598,000
Discoveries, extensions and improved recoveries, net of future development cost		2,298,000			3,054,000
Change in future development costs		—			—
Development costs incurred during the period that reduced future development cost		—			—
Sales of reserves in place		—			—
Revisions of quantity estimates		(4,745,000	)		2,639,000
Accretion of discount		4,279,000			1,865,000
Net change in income taxes		16,594,000			(4,221,000	)
Purchase of reserves		—			361,000
Changes in timing of rates of production		(4,402,000	)		(3,233,000	)


Standardized measure, end of period	$	7,199,000		$	24,960,000

ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A
CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

The Chief Executive Officer and Principal Accounting Officer evaluated the effectiveness of the Company’s disclosure controls and procedures and concluded that, following implementation of the changes in internal control over financial reporting discussed below, the Company’s disclosure controls and procedures were effective as of March 31, 2009.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the year ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

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

Our internal control over financial reporting includes those policies and procedures that;

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the directors of the Company; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements, and provide reasonable assurance as to the detection of fraud.

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

With the participation of the Chief Executive Officer and Principal Accounting Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, the Company’s management concluded that the Company’s internal control over financial reporting was effective as of March 31, 2009.

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


By:	/s/ Ray Singleton	By:	/s/ Joseph Young
	Ray Singleton, President		Joseph Young
	Chief Executive Officer		Principal Accounting Officer
	June 18, 2009		June 18, 2009

ITEM 9B
OTHER INFORMATION

There is no information required to be disclosed on Form 8-K during the fourth quarter of the year ended March 31, 2009 that has not been reported.

Part III

ITEM 10
DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Directors

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

Ray Singleton (58) has been a director of Basic since July 1989. Mr. Singleton joined the Company in June 1988 as Production Manager/Petroleum Engineer. In October 1989, he was elected Vice President, and was appointed President and Chief Executive Officer in March 1993. Mr. Singleton began his career with Amoco Production Company in Texas as a production engineer. He was subsequently employed by the predecessor of Union Pacific Resources as a drilling, completion and production engineer and in 1981 began his own engineering consulting firm, serving the needs of some 40 oil and gas companies. As a consultant he was retained by the Company on various projects from 1981 to 1987. Mr. Singleton currently serves on the Board of Directors of the Independent Petroleum Association of Mountain States (IPAMS) and is a former president of that organization. IPAMS is a thirteen-state, regional trade association that represents the interests of independent oil and gas companies in the Rocky Mountain region. In addition, Mr. Singleton is a member of the Society of Petroleum Engineers. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1973 and received a Masters Degree in Business Administration from Colorado State University’s Executive MBA Program in 1992.

Richard K. Rodgers (49) has been a director of Basic since December 2006. Mr. Rodgers was originally appointed to fill the vacancy created by the resignation of a prior director, and was then elected as a director at the Company’s shareholder meeting held on January 15, 2007. For the last three years, Mr. Rodgers has provided business development, planning and financial consulting services to various banking and business development clients. During the past five years, Mr. Rodgers was employed by several Denver area banks including Key Bank, Guaranty Bank & Trust Company and Colorado Capital Bank. In his most recent employment with Colorado Capital Bank from 2004 to 2005, he was the President, and was responsible for the start-up, of its Cherry Creek branch office and served on the Board of Directors of Colorado Capital Bank. Mr. Rodgers attended the University of Denver and received his Bachelor of Science degree in International Business Administration in 1995 and his Master of Science degree in International Business Administration in 1997.

Monroe W. Robertson (59) was originally appointed to fill the vacancy created when the Board, on April 4, 2007, amended the Company’s Bylaws to increase the number of members of the Board from three (3) members to four (4) members. Subsequently, he was elected as a director at the Company’s shareholder meeting held on January 21, 2008. Mr. Robertson currently serves on the Board of Directors of Cimarex Energy Company and is chairman of that board’s Audit Committee. Mr. Robertson began his career in 1973 with Gulf Oil Corporation and held various positions in engineering, corporate planning and financial analysis until 1986. From 1986 to 1992 he held various positions at Terra Resources and Apache Corporation. In 1992 Mr. Robertson joined Key Production Company as its Senior Vice President and Chief Financial Officer. In 1999 he was appointed President and Chief Operating Officer of that company and served in that role until 2002. Other than his service on Cimarex’s board which began in October 2005, for the past five years Mr. Robertson has been a private investor. Mr. Robertson received a Bachelor of Science degree in Mechanical Engineering along with Master of Science degrees in both Mechanical Engineering and Nuclear Engineering from the Massachusetts Institute of Technology in 1973. He also has received a Masters Degree in Business Administration from National University in 1979. Mr. Robertson is a member of the National Association of Corporate Directors.

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

Executive Officers

In February 2008, Mr. Flake resigned as an officer of the Company, and then as a director in October 2008. Prior to this, the Company’s executive officers were Ray Singleton and David Flake. Both were also board members. Subsequent to Mr. Flake’s resignation as an officer, we hired on a contract basis Joseph Young as Principal Accounting Officer. The names, ages, principal occupations and/or employment during the past five years are set forth above for Ray Singleton and below for Joseph Young. There are no family relationships between or among the officers and Board of Directors.

Joseph Young

Joseph Young (30) joined the Company in March 2008 as the Company’s Principal Accounting Officer, subsequent to the resignation of David Flake. Mr. Young began his public accounting career at PricewaterhouseCoopers in the Silicon Valley area, where he audited multiple public and private companies for financial reporting and Sarbanes-Oxley compliance. Since then, he has provided accounting, reporting, and compliance services to a variety of businesses within the oil and gas, mining and technology sectors. Mr. Young previously served as Chief Financial Officer for JayHawk Energy, Inc. and Controller for Fellows Energy, Inc. Mr. Young received his Bachelor of Arts degree in Accounting from the University of Utah in 2002.

Involvement in Certain Legal Proceedings

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

Corporate Governance

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

Audit Committee. The Board of Directors has a standing Audit Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson. During fiscal 2009 the Audit Committee met eight times. The Audit Committee is authorized to review, with the Company’s independent accountants, the annual financial statements of the Company prior to publication and to make annual recommendations to the Board for the appointment of independent public accountants for the ensuing year. It is the responsibility of the Audit Committee to review the effectiveness of the financial and accounting functions, operations, and internal controls implemented by Basic’s management.

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

Compensation Committee. The Board of Directors has a standing Compensation Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson, both of whom are independent under the guidelines of the American Stock Exchange listing standards. Mr. Rodgers serves as the Committee’s chairman. The responsibilities of the Compensation Committee (the “Committee”) of the Board of Directors are three-fold: first, establishing and administering the general compensation policies of the Company, second, setting the specific compensation for the Company’s chief executive officer (CEO) and lastly, recommending to the Board of Directors the independent director compensation.

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

Nominating Committee. The Board of Directors has a standing Nominating Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson.

No material changes have been made to the procedures by which security holders may recommend nominees to the Board of Directors since we filed with the Securities and Exchange Commission, on October 28, 2008, its definitive proxy statement for the 2008 Annual Meeting of Shareholders.

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

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

Section 16(a) of the Securities Exchange Act requires the Company’s officers and directors and shareholders of more than ten percent of the Company’s common stock to file reports of ownership and changes in ownership of the Company’s common stock with the Securities and Exchange Commission (SEC). Officers and directors are required by SEC regulations to furnish Basic with the information necessary for the Company to file all required Section 16(a) reports. During fiscal 2009 all required reports were filed timely.

ITEM 11
EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the compensation paid or accrued by the Company to its Chief Executive Officer and Principal Accounting Officer for fiscal 2009 and 2008. No other director, officer or employee received annual compensation that exceeded $100,000.


							Non-Equity		All
Name and	Fiscal		Salary		Bonus		Incentive Plan		Other		Total
Principal Position	Year		($)		($)		Compensation		Compensation		($)
					(1)		(2)		(3)
Ray Singleton		2009	$	183,574	$	29,307	$	9,563	$	6,073	$	228,517
President and Chief Executive Officer		2008	$	134,250	$	6,346	$	4,053	$	6,176	$	150,825

Joseph Young		2009	$	110,169	$	5,000	$	—	$	—	$	115,169
Principal Accounting Officer


(1)		The amount shown for each executive officer is the amount accrued for in prior periods and paid in fiscal 2009.

(2)		The amount shown for each executive officer is the amount accrued for fiscal 2009 and paid for fiscal 2008 through the Oil and Gas Incentive Compensation Plan.

(3)		For Mr. Singleton, amount includes matching funds contributed by the Company to its 401(k) plan of $5,826 and $5,204 for fiscal 2009 and 2008, respectively. It also includes $247 and $850 for premiums paid by the Company on a life insurance policy for Mr. Singleton during fiscal 2009 and 2008, respectively. Mr. Singleton designates the beneficiary.

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

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

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

Of the 1,000,000 shares authorized under the ISO Plan, prior to its expiration, options for only 665,000 shares were granted. Of that amount and as of March 31, 2009, 50,000 options expired unexercised, and 615,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share.

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

Outstanding Equity Awards at Fiscal Year End

As of March 31, 2009, there were no outstanding equity option awards held by either executive officer or by any of the directors.

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

Director Compensation

Prior to fiscal 2008, directors received no cash compensation for their services to the Company as directors, but were reimbursed for out-of-pocket expenses incurred to attend board meetings. However, from July 1995 until its expiration in July 2005, the Incentive Stock Option Plan (“the ISO Plan”), noted above, provided eligible, non-employee members of the Board of Directors of Basic or its subsidiaries (Non-Employee Directors), grants of certain options to purchase common stock of the Company, as compensation for their services. During the years the ISO Plan was active, 425,000 non-qualified options were granted to independent directors: 175,000 to David Flake, our former CFO, who was then an outside director of the Company. As of March 31, 2009, there were no unexercised stock options.

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

With respect to this Plan, independent director compensation consists of a cash retainer, meeting fees, committee fees and stock grants. Independent directors receive an annual cash retainer of $16,000, in addition to $2,000 and $500 for quarterly board meetings and committee meetings (which take place as needed), respectively. Committee chairpersons of the Audit, Compensation, and Nominating Committees receive $5,500, $4,500 and $3,500, respectively. Additionally, independent board members receive an annual stock grant equal to $36,000 vested over three years. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date. Thus, effective April 1, 2008 and April 1, 2009, subject to vesting, Messrs. Robertson and Rodgers are entitled to stock grants of 36,036 and 44,888 shares each, respectively.


	Fees Earned or				All Other
	Paid in Cash		Stock Awards		Compensation		Total
Name	($)		($)		($)		($)
			(1)
Richard Rodgers	$	33,000	$	36,000	$	—	$	69,000
Monroe Robertson		34,000		36,000		—		70,000

Total		67,000		72,000		—		139,000


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

ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Set forth below, as of June 18, 2009, is information concerning stock ownership of all persons, or group of persons, known by the Company to own beneficially 5% or more of the shares of Basic’s common stock and all directors and executive officers of the Company, both individually and as a group, who held such positions in fiscal 2009. Basic has no knowledge of any other persons, or group of persons, owning beneficially more than 5% of the outstanding common stock of the Company as of March 31, 2009.

Shares of

Percent of

Common

Outstanding

Stock

Shares

Beneficially

Name and Address of Beneficial Owner

Type and Class

Owned

Ray Singleton, Denver CO (a)

Common Stock

4,505,912

25.7

Richard Rodgers, Denver, CO (c)

Common Stock

7,571

(d)

Monroe W. Robertson, Denver, CO (d)

Common Stock

13,471

(d)

All officers and directors as a group (3 persons) (a), (b), and (c)

Common Stock

4,526,954

25.7


(a)		All 4,505,912 shares are owned directly by Mr. Singleton.

(b)		All 7,571 shares are fully vested and owned directly by Mr. Rodgers

(c)		All 13,471 shares are fully vested and owned directly by Mr. Robertson.

(d)		Less than 1%

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

ITEM 13
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

With respect to prospects initiated during either fiscal 2009 or 2008, none of Basic’s officers or directors participated with the Company. However, in previous years, Mr. Singleton participated with the Company in certain acquisitions. With respect to his working interest in the four wells in which he currently has a working interest, at March 31, 2009 Mr. Singleton had a balance owed to the Company of less than $1,000 compared to a balance due to him of approximately $2,000 at March 31, 2008. This was due to his share of operating expenses exceeding the amount due to him for his share of oil and gas revenue from these wells.

ITEM 14
PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table discloses the fees that the Company was billed (and anticipates being billed) for professional services rendered by its independent public accounting firm in each of the last two fiscal years.


	Years Ended
	March 31,
	2009		2008
Audit fees (1)	$	92,000	$	70,000
Audit-related fees(2)		4,000		—
Tax fees(3)		—		11,500
All other fees(4)		—		—


Total	$	96,000	$	81,500


(1)		Reflects fees billed for the audit of the Company’s consolidated financial statements included in its Form 10-K and review of its quarterly reports on Form 10-Q.

(2)		Reflects fees, if any, for services related to financial accounting and reporting matters.

(3)		Reflects fees billed for tax compliance, tax advice and preparation of the Company’s federal tax return.

(4)		Reflects fees, if any, for other products or professional services not related to the audit of the Company’s consolidated financial statements and review of its quarterly reports, or for tax services.

Pre-Approval Policies and Procedures

The Audit Committee approves all audit, audit-related services, tax services and other services provided. Any services provided that are not specifically included within the scope of the audit must be pre-approved by the Audit Committee in advance of any engagement. Under the Sarbanes-Oxley Act of 2002, audit committees are permitted to approve certain fees for audit-related services, tax services and other services pursuant to a de minimus exception prior to the completion of an audit engagement. In fiscal 2009, none of the fees paid to Ehrhardt Keefe Steiner & Hottman PC were approved pursuant to the de minimus exception.

Part IV

ITEM 15
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibits


Exhibit
No.			Document
	3i	¹	Restated Certificate of Incorporation included in Basic’s Form 10-K for the year ended March 31, 1981
	3i	¹	By-laws included in Basic’s Form S-1 filed October 24, 1980
	3i	¹	Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996
	10(i)a	¹	Loan Agreement between The Bank of Cherry Creek and Basic, dated March 4, 2002
	10(i)a	¹	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.
	10(i)a	¹	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated December 31, 2006
	10(ii)	¹	Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985
	10(ii)	¹	Restricted Stock Agreement dated effective as of April 7, 2007
	21	¹	Subsidiaries of Basic included in Basic’s Form 10-KSB for the year ended March 31, 2002
	31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
	31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer)
	32.1		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
	32.2		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).


¹		Previously filed and incorporated herein by reference

Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.

EXHIBIT INDEX

Exhibits


Exhibit
No.			Document
	3i	¹	Restated Certificate of Incorporation included in Basic’s Form 10-K for the year ended March 31, 1981
	3i	¹	By-laws included in Basic’s Form S-1 filed October 24, 1980
	3i	¹	Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996
	10(i)a	¹	Loan Agreement between The Bank of Cherry Creek and Basic, dated March 4, 2002
	10(i)a	¹	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.
	10(i)a	¹	Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated December 31, 2006
	10(ii)	¹	Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985
	10(ii)	¹	Restricted Stock Agreement dated effective as of April 7, 2007
	21	¹	Subsidiaries of Basic included in Basic’s Form 10-KSB for the year ended March 31, 2002
	31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
	31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer)
	32.1		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
	32.2		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).


¹		Previously filed and incorporated herein by reference

Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.


	Page

Part I

Item 1 Description of Business		4

Item 1B Unresolved Staff Comments		9

Item 2 Description of Property		9

Item 3 Legal Proceedings		11

Item 4 Submission of Matters to a Vote of Security Holders		11

Part II

Item 5 Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		12

Item 6 Selected Financial Data		13

Item 7 Management’s Discussion and Analysis and Plan of Operation		13

Item 7A Quantitative and Qualitative Disclosures About Market Risk		18

Item 8 Financial Statements		19

Item 9 Changes In and Disagreements With Accountants on Accounting and Financial Disclosure		41

Item 9A Controls and Procedures		41

Item 9B Other Information		42

Part III

Item 10 Directors, Executive Officers, and Corporate Governance		43

Item 11 Executive Compensation		46

Item 12 Security Ownership of Certain Beneficial Owners and Management		48

Item 13 Certain Relationships and Related Transactions		49

Item 14 Principal Accountant Fees and Services		49

Part IV

Item 15 Exhibits and Financial Statement Schedules		50

Signatures		51

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


Name and Capacity		Date


By:	/s/ Ray Singleton	June 18, 2009
	Ray Singleton, Director

By:	/s/ Richard K. Rodgers	June 18, 2009
	Richard K. Rodgers, Director and
	Compensation Committee Chairman

By:	/s/ Monroe W. Robertson	June 18, 2009
	Monroe W. Robertson, Director and
	Audit Committee Chairman


	Page
Report of Independent Registered Public Accounting Firm — Ehrhardt Keefe Steiner & Hottman PC		20

Report of Prior Independent Registered Public Accounting Firm — Hein & Associates LLP		21

Consolidated Balance Sheets		22–23

Consolidated Statements of Operations		24

Consolidated Statements of Shareholders’ Equity		25

Consolidated Statements of Cash Flows		26

Notes to Consolidated Financial Statements		27–40