EARTHSTONE ENERGY INC - Annual Report: 2009 (Form 10-K)

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.

Basic Earth Science Systems, Inc.
Form 10-K
March 31, 2009

Table of Contents

		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

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

30,200

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 expense2,3,4		$	26.09			$	19.27			$	18.61
Gross profit3,4		$	47.61			$	43.96			$	36.17
Depletion expense3,4		$	10.03			$	5.59			$	4.85
General and administrative expense3,4		$	11.04			$	5.94			$	4.20

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.

ITEM 8
FINANCIAL STATEMENTS

Basic Earth Science Systems, Inc.
Table of Contents
Consolidated Financial Statements
and Accompanying Notes
March 31, 2009 and 2008

		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

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.

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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Basic Earth Science Systems, Inc. and subsidiaries as of March 31, 2008 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.

		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.

		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.

										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.

		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.

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	)