UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

   
þ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended March 31, 20092010
   
o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 0-7914
BASIC EARTH SCIENCE SYSTEMS, INC.
633 17thStreet, Suite 1645(Exact Name of Registrant as Specified in its Charter)

Denver, Colorado 80202-3625
Telephone (303) 296-3076
Delaware
(State of Incorporation or Organization)
84-0592823
(I.R.S. Employer Identification No.)
633 17th Street, Suite 1645
Denver, Colorado
(Address of principal executive office)
80202-3625
(Zip Code)
 (303) 296-3076
(Registrant’s telephone number, including area code)
  
Incorporated in DelawareIRS ID# 84-0592823

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yeso Noþ

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yeso Noþ

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site,Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)filed).  Yeso Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
Issuer’s
Registrant’s revenues for its most recent fiscal year: $9,086,000$7,269,000

The aggregate market value of registrant’s common stock held by non-affiliates was approximately $10,163,524 as of the registrant’s most recently completed second fiscal quarter.

As of June 18, 2009, 17,505,7272010, 17,102,521 shares of the registrant’s common stock were outstanding,outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13 and the aggregate market value14 of such common stock heldPart III is incorporated by non-affiliates was approximately $21,831,981 asreference from portions of the registrant’s most recent second fiscal quarter end.definitive Proxy Statement for its 2010 Annual Meeting of Stockholders to be filed, pursuant to Regulation 14A, no later than 120 days after March 31, 2010.
 


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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”"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;
•      our strategies, either existing or anticipated;
amounts and nature of future capital expenditures;
•      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; 
acquisitions and other business opportunities;
•      amounts and nature of future capital expenditures;
operating costs and other expenses;
•      acquisitions and other business opportunities;
wells expected to be drilled;
•      operating costs and other expenses;
asset retirement obligations; and
•      wells expected to be drilled, other anticipated exploration efforts and the expenses associated therewith;
•      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.

    •      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.time. 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 theseany 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 on 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.

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Basic Earth Science Systems, Inc.
Form 10-K
March 31, 2009
2

Earthstone Energy, Inc.
Form 10-K
March 31, 2010
Table of Contents

 Part IPage
Item 14
Item 1A8
Item 1B8
Item 28
Item 313
   
 PagePart II 
   
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1214
1316
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Item 824
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44
Item 9A44
Item 9B44
  
41Part III 
   
Item 1046
Item 1146
Item 1246
Item 1346
Item 1446
  
41Part IV 
   
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49
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51
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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Part I
ITEM 1
DESCRIPTION OF BUSINESS
Overview

Overview

Earthstone Energy, Inc. was incorporated in Delaware in 1969 as Basic Earth Science Systems, Inc.  We changed our name in 2010 to Earthstone Energy, Inc.  Earthstone Energy, Inc. (“Basic”Earthstone” 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 areprimarily engaged in the exploration acquisition,and development operation, production and sale of crude oil and natural gas.gas properties. We have an established production base that generates positive cash flow from operating activities and profits. Our operating 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 the 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 continue to anticipate emphasizing acquisitionsthe acquisition of producing properties over drilling in the coming year.  While we will be drilling a considerable number of wells for our size (primarily to protect expiring leases and maintain our interests under exploration agreements)existing acreage holdings), we are not expecting our partners to drill at current commodity prices. Finally, weacquire large, new, non-producing acreage positions in the coming year.  We will also be focusing on reducingkeeping our operating costs under control as rigswe expect rig and vendor services becomeservice costs to rebound due to high demand.  We caution that the following expectations may be altered by subsequent events or other, more available.attractive opportunities that may present themselves in the future.

Over the last two years, improvements in hydraulic stimulation technology have yielded significantly improved production rates in formations whose physical characteristics were once considered uneconomic.  Previously unknown formations, such as the Marcellus, Haynesville, Eagle Ford, Bakken and recently the Niobrara, are now common names in the oil and gas industry.  By virtue of the producing properties Earthstone has in Montana, North Dakota and Colorado, the Company has exposure to both the ongoing development of the Bakken formation in the Williston basin and now exposure to the new Niobrara play in Colorado.
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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 expectintend 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 twoseveral 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.year.  These areas are our on-going Banks prospect in McKenzie County, North Dakota, our Indian Hill acreage also in McKenzie County and our South Flat Lake prospectacreage in Divide County, North Dakota and 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.

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Banks ProspectField — McKenzie County, North Dakota.In the fall of 2008, we disclosed that we farmed out our   Earthstone retains a 6.5% working interest in approximately 13,000 gross (845 net) acres in the immediate vicinity of this prospect tofield.  To date, eight horizontal wells have been drilled; five in which the Company holds an interest.  Both Panther Energy Company, LLC (Panther), while retaining a 6.5% working interest. Panther has drilled and completedZenergy, Inc. have permitted wells on numerous spacing units which Earthstone, in-part, owns.  While the two wells they were required to drill under the agreement, and have stated that they will curtail drilling until oil prices areCompany expects future activity in this area in the $75 per barrel range.upcoming year, we have not received any indication of when either company may commence additional drilling efforts.
South Flat Lake Prospect
Indian Hill Field — McKenzie County, North Dakota.   The Company holds approximately 960 gross (192 net) acres in the Indian Hill Field.  Several horizontal wells have been drilled within four miles of this acreage.  With improving hydraulic stimulation technology, Earthstone anticipates that this acreage will be evaluated for horizontal Bakken development in the coming year.

Divide County, North Dakota  — Sheridan County, Montana.We  Recently, several companies have acquired leasesdrilled horizontal Bakken wells in these two counties.  Little is known about the success of these efforts, especially on approximately 4,200 gross acres (1,900 net)wells that have used newer hydraulic stimulation technology.  However, leasing and leasehold prices are escalating in northern Sheridan County near the Flat Lake Field. Developed by a geologist on retainermanner similar to us, South Flat Lake represents the first exploration prospect we have generatedthat seen earlier 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 shareareas that are now being aggressively drilled for Bakken production.  By virtue 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 Commissionproducing properties Earthstone has granted a drilling permit, andin these two counties, along with undeveloped leasehold acreage, the surface locationCompany has been prepared for drilling operations. If oil commodity prices continue their recent upward trend, we believe itapproximately 3,800 gross (2,400 net) acres which could be feasible to commence drilling operations beforeevaluated for horizontal Bakken development in the end of the calendarcoming 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 disclosedAt March 31, 2009, Earthstone finished the first phase of our plansproject to drill and complete sixteen new 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 allAll development work on the first phase on this effort640 acre section has been finalized.  At March 31, 2010, we have begun our second and third phase of this project; to drill the “edge wells” around this section of land and to deepen some of the existing Codell wells to the J-Sand formation.  For the six new “edge wells” the Company will hold a proportionately reduced interest due to having our acreage “pooled” with adjoining acreage.  We expect to have a 2%1% to 52.5%26.25% revenue interest in Codell/Niobrara production and a 13.125% to 52.5% revenue interest in J-Sand production.from these wells. The working and revenue interest percentage for each individual well is different and is determined by the specific bottom-hole location of thateach respective well.  In addition,On the respective working and revenue intereststhird phase of this project, ten of the Codell/Niobrara andnew Codell wells will be recompleted in the J-Sand formations may be differentformation.  The Company expects to have a 13.125% to 52.5% revenue interest in a specific well.J-Sand production.  These respective interests are also determined by the specific bottom-hole location of thateach respective well and the spacing unit attributable to that well.  However, all new wells currently produce only fromIn addition, in any given well, the respective working and revenue interests of the Codell/Niobrara formation.production may be different when compared to the working and revenue J-Sand production.  Kerr-McGee Oil & Gas Onshore, LP is the operator of the project.
Christmas Meadows Prospect — Summit
In the past few months, word of successful horizontal Niobrara wells has created a frenzy of leasing activity in Colorado and Wyoming.  Earthstone has rights to the Niobrara formation in Weld County, Utah.In fiscal 2007, we participated with Double Eagle Petroleum Company (“Double Eagle”) in one ofColorado.  Similar to our Codell formation interests, should horizontal Niobrara wells be drilled on this section, the more exciting, true wildcat projectsworking and revenue interest percentage for each individual well will be based on our proportionate interest in the Rocky Mountain region, Christmas Meadows. Christmas Meadows is a structural dome in the southwest cornerspecific spacing unit designated for that well.

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Table 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.Contents

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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.  Generally, at any one time, we are engaged in various stages of due diligence in connection with one or more drilling or acquisition opportunities.  Unless required by applicable law, our policy is generally to not disclose the specifics of any such opportunity until such time as that transaction is finalized and we have entered into a definitive agreement regarding the same and then, only when such transaction is material to our business.  Similarly, we do not speculate on the outcome of such ventures until the drilling, production or other results are available and have been verified by us.

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 nodo not own or operate any gas gathering transportation, refining or marketing functions.processing plant facilities nor do we possess sufficient volume on any pipeline to market our product to end users.

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 marketMarkets for and the value of, oil and natural gas are dependent upon a number ofvolatile and are subject to wide fluctuations depending on numerous factors beyond our control, including other sources of production, competitive fuels and proximity and capacity of pipelines or other means of transportation, seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies.  Substantially all of whichour gas production is sold at prevailing wellhead gas prices, subject to additional charges customary to an area.

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.

Major Customers.  In the year ended March 31, 2010, approximately 43% of our oil and gas production revenues were received from sales to six purchasers.  It is not expected that the loss of any one of these purchasers would cause a material adverse impact on our operations because alternative markets for our products are beyondreadily available.  The remaining 57% of our control. Forrevenue was received from non-operated properties where we have no control over the selection of the purchaser.  On these properties our portion of the product is marketed on our behalf by the 21 different companies who operate these wells.  These 21 companies may, unbeknownst to us, market to one or more information seeof the same purchasers that we use.  Therefore, we are unable to ascertain the total extent of combined purchaser concentration.  To the extent of our knowledge, in the event of the bankruptcy of any one of our purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%.  See also 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  Competition is intense with respect to acquisitions competition is intense forand the purchase of large producing properties. Becauseproperties because of the limited capital resources available to us,us.  As such, we have historically focused on smaller and/or marginal properties with behind-pipe potential in our acquisition efforts.  Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.
Regulations
Employees

At March 31, 2010, we had nine full-time and two part-time employees.  Four of these employees are primarily field laborers and are located at our subsidiary’s field office in Bruni, Texas, forty-five miles southeast of Laredo, Texas.   In addition, in other areas, we have six contract field workers on a part-time retainer basis.  We believe our employee and contractor relations are good.

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.locations, occupational health and safety, control of toxic substances, and other matters involving environmental protection. These laws are continually changing and, in general, are becoming more restrictive. We are further affected by changeshave made, and expect to make in the future, significant expenditures to comply with such laws and by administrative regulations. ToChanges to current local, state or federal laws and regulations in the bestjurisdictions where we operate could require additional capital expenditures and result in an increase in our costs. Although we are unable to predict what additional legislation, if any, might be proposed or enacted, additional regulatory requirements could impact the economics 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.projects.

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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

RISK FACTORS

While we acknowledge that we have certain risk factors, smaller reporting companies are not required to provide information under this Item.  Therefore, the absence 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 inreporting under 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.

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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,Item should not be construed to indicate that we have no risk factors.  Instead, we recognize that we have the same or similar risk factors as the currentother comparable companies within our industry; especially companies with similar 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, developcapitalization 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.employee census.
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 toCompetitionandRegulationsunder 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.

8


ITEM 1B
UNRESOLVED STAFF COMMENTS

None.

DESCRIPTION OF PROPERTY

Producing Properties: Location and Impact

At March 31, 2009,2010, we owned a working interest in 94101 producing oil wells and 3639 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 toCredit Lineunder Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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 
             
Productive Wells

  Gross Wells (1)  Net Wells (2) 
  Oil  Gas  Oil  Gas 
                 
Colorado     37      7.50 
Louisiana  1   1   0.01   0.10 
Montana  20      9.77    
North Dakota  56      9.64    
Texas  23   1   20.66   0.11 
Wyoming  1      0.47    
                 
Total  101   39   40.55   7.71 

(1)The number of gross wells is the total number of wells in which a working interest is owned.
(2)A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

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 of Financial Condition and PlanResults of Operation.Operations.

Reserves

At March 31, 2009,2010, our estimated proved developed and undeveloped oil and gas reserves in barrels of oil equivalent (BOE) was 794,000,970,000, a 35.4% decrease22.2% increase from the prior year’s estimated proved developed oil and gas reserves of 1,229,000794,000 BOE.  This decreaseincrease was primarily caused by a 51.1% reductionan increase in the 12 month average of the price of oil from $101.58 at March 31, 2008and gas on the first day of each month during fiscal 2010 when compared to $49.66 atthe price on  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.

9


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 and undeveloped oil and gas reserves divided between operated and non-operated properties for these three areas as of March 31, 2009:2010:

                 
  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%
             
Estimated Proved Oil and Gas Reserves by Area
  Net Oil  Net Gas  BOE    
  (Bbls)  (Mcf)  (1)  % 
             
Williston Basin            
     Operated  202,000   45,000   210,000   21.6%
     Non-Operated  248,000   152,000   273,000   28.1%
                 
   450,000   197,000   483,000   49.7%
                 
South Texas/Onshore Gulf Coast                
     Operated  312,000   2,000   312,000   32.2%
     Non-Operated     126,000   21,000   2.2%
                 
   312,000   128,000   333,000   34.4%
                 
D-J Basin                
     Operated  16,000   310,000   68,000   7.0%
     Non-Operated  40,000   277,000   86,000   8.9%
                 
   56,000   587,000   154,000   15.9%
                 
Total  818,000   912,000   970,000   100%
(1)Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)

In March 2010, we adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved reserves within the Modernization of Oil and Gas Reporting rules, which were issued by the Securities and Exchange Commission (“SEC”) at the end of 2008. The new accounting standard requires that the 12-month average of the first-day-of-the-month price for the preceding year, rather than the year-end price, be used when estimating reserve quantities. Furthermore, it permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Prior-year data are presented in accordance with Financial Accounting Standards Board (“FASB”) oil and gas disclosure requirements effective during those periods.
Preparation of Proved Reserves Estimates

Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance. Oil and gas reserves have been estimated as of March 31, 2010 for a significant portion of our properties by the Ryder Scott Company (“Ryder Scott”) of Houston, Texas. Ryder Scott estimated reserves for properties located in the states of Colorado, Louisiana, Montana, North Dakota and Texas comprising approximately 93% and 98% of the PV-10 of our oil and gas reserves as of March 31, 2010 and March 31, 2009, respectively.  Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years.  Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  Ryder Scott has over eighty engineers and geoscientists on their permanent staff.  Ryder Scott prepares our reserve estimate based upon a review of property interests being appraised, production from such properties, average annual costs of operation and development, commodity prices for production that comply with the new SEC guidelines and other engineering data/information we provide to them. This information is reviewed by knowledgeable members of our company, including our President and Chief Executive Officer, to ensure accuracy and completeness of the data prior to and after submission to Ryder Scott.  The report of Ryder Scott dated May 3, 2010, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.3 to this report.
We concluded that it was not cost effective to have Ryder Scott prepare reserve estimates for 32 of our 91 properties because of their relatively low values.  Instead, reserves for these properties were prepared by in-house personnel and contributed 7% and 2% of our reserves as of March 31, 2010 and March 31, 2009, respectively.  In-house reserve estimates were prepared by Ray Singleton, President and Chief Executive Officer.  Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.  In his capacity as an engineer, Mr. Singleton prepared reserve and economic estimates during his employment with both Amoco Production Company and Champlin Petroleum.  Mr. Singleton continued providing economic evaluations for approximately 40 different clients through his engineering consulting firm, Singleton & Associates, from 1982 to 1988, and thereafter for Earthstone Energy, Inc. since his employment in 1988.  In addition, Mr. Singleton is currently a member of the Society of Petroleum Engineers.

Technologies Used in Preparation of Proved Reserves Estimates

All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods used are limited to decline curve analysis which utilized extrapolations of historical production data.   All proved undeveloped reserves were estimated by analogy.  This is done by consideration of the assumptions, data, methods and analytical procedures.

Oil and gas reserves and the estimates of the present value of future net revenues were determined based on prices and costs as prescribed by SEC and FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods.  Proved reserves were estimated in accordance with guidelines established by the SEC and FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.

The following table sets forth certain information regarding estimates of our oil and gas reserves as of March 31, 2010. All of our reserves are located in the United States.
Estimated Proved Developed and Undeveloped Oil and Gas Reserves

  Proved    
  Developed       
  Producing  Non-Producing  Undeveloped  Total Proved (1) 
             
Net Remaining Reserves            
     Oil/Condensate - Bbls  727,000      91,000   818,000 
     Plant Products - Bbls            
     Gas - MCF  912,000         912,000 

(1)Disclosure of probable and possible reserves became optional under SEC guidelines for years ended March 31, 2010, and accordingly, we have elected not to present probable or possible reserves.
The process of estimating oil and gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are inherently imprecise.  Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Annual Report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.
Proved Undeveloped Reserves
At March 31, 2010, we had 91,000 barrels of proved undeveloped reserves, which will require future capital expenditures of approximately $991,000 to develop. At March 31, 2009 we had one proved undeveloped property. During fiscal 2010 this property was re-classified to the proved and developed category.  Approximately $490,000 was spent in this development effort. None of the proved undeveloped reserves at March 31, 2010 have been on our reserve report for more than five years.

Oil  and Gas Production and Sales Prices
Refer to Selected Financial Information in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the table which presents our net oil and gas production, the average sales price per Bbl of oil and per Mcf of gas produced and the average cost of production per BOE of production sold, for the three years ended March 31, 2010.

Drilling Activities
The following table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended March 31, 2010:

Exploratory and Developmental Wells Drilled

   2010   2009   2008 
   Gross   Net   Gross   Net   Gross   Net 
Exploratory (1)                        
     Productive                        
        Oil        1   0.01       
        Gas                  
     Dry holes  1   0.55             
                         
Total  1   0.55   1   0.01       
                         
Development (2)                        
     Productive                        
        Oil  5   0.36   3   0.09       
        Gas        9   2.27   7   1.60 
     Dry holes                  
                         
Total  5   0.36   12   2.36   7   1.60 

(1)An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

(2)A development well is a well drilled in a proven territory in a field to complete a pattern of production

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 explorationacreage as follows:
Gross and development drilling, we have begun to acquire various developed and undeveloped leasehold interests.Net Acreage
                 
  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 
             

10

  Developed Acreage  Undeveloped Acreage (1) 
  Gross (2)  Net (3)  Gross (2)  Net (3) 
                 
Colorado            640             384    —    — 
Louisiana            687               51    —    — 
Montana         6,490          3,206          2,761          2,123 
North Dakota       14,856          2,952        26,506          4,623 
Texas         3,080          2,486    —    — 
Utah   —    —        35,945             719 
Wyoming         1,555             329               40                 1 
                     
Total       27,308          9,408        65,252          7,466 


(1)
Undeveloped acreage encompasses leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas.
(2)
The number of gross acres is the total number of acres in which a working interest is owned.
(3)A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Field Service Equipment
At March 31, 2009, one of2010, our subsidiaries,remaining active subsidiary, 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$5,853 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.
LEGAL PROCEEDINGS

None.

ITEM 4
SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS
There were no matters submitted during the fourth quarter
13



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

Price Range of Common Stock, Number of Holders and Dividend Policy

Our common stock is traded incurrently quoted on the over-the-counter market. Over-the-Counter Bulletin Board (“OTCBB”).  The OTCBB is a network of security dealers who buy and sell stock. The dealers are connected by a computer network that provides information on current “bids” and “asks,” as well as volume information. Our shares are quoted on the OTCBB under the symbol “BSIC.”

The following table sets forth the range of high and low closing bid pricesquotations for our common stock 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 onperiods indicated below as reported by the over-the-counter marketOTCBB. These quotations reflect inter-dealer quotations,prices, without adjustments for retail mark-ups, mark-downsmark-up, mark-down or commissions to the broker-dealercommission and may not necessarily represent actual transactions.  The closing bid price on June 18, 2010 was $1.30.

  High  Low 
         
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 
         
Year Ended March 31, 2010        
     First Quarter $0.99  $0.65 
     Second Quarter  0.95   0.73 
     Third Quarter  0.89   0.68 
     Fourth Quarter  0.93   0.70 

As of June 18, 2009,2010, we had approximately 2,0313,919 shareholders of record. We have never paid a cash dividend on our common stock. Our loan agreement has a covenant prohibiting the payment of dividends to stockholders without our lender’s prior written consent.  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 and financial condition, receipt of our lender’s consent and other factors. Our Board of Directors presently has no plans to pay any dividends in the foreseeable future.
Purchases
Unregistered Sales of Equity Securities

Not applicable.

Securities Authorized For Issuance under Equity Compensation Plans
The following table summarizes stock repurchase activity forcontains information with respect to our Director Compensation Plan as of the quartersend of our fiscal year ended December 31, 2008
and March 31, 2009:2010.
                 
          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     
               

Equity Compensation Plan Information

Plan Category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted-average exercise price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plans
   
(1)Equity compensation plans approved by security holders N/A
Equity compensation plans not approved by security holdersN/A300,000
Total
N/A
300,000

The Board adopted a Director Compensation Plan (the “Plan”), effective April 1, 2007, which provides for a combination of cash and equity incentive compensation to attract and retain qualified and experienced director candidates. Under the Plan, each independent, non-employee director receives an annual grant of restricted stock having a fair market value equal to $36,000 on April 1 of each year. The number of shares included in each annual grant is determined based upon the average closing price of the ten trading days preceding April 1 of each year. Up to 507,276 shares of the Company’s common stock may be issued to directors under the Plan, subject to certain restrictions and vesting. Grants of shares of restricted stock vest one-third each year over three years.

During the end of our fiscal year ended March 31, 2010, 207,276 shares of common stock reserved for issuance under the Plan had been authorized for issuance. On March 31, 2010, the Plan was amended to authorize an additional 300,000 shares for issuance. As of June 18, 2010, 294,444 shares of common stock reserved for issuance under the Plan had been granted. Accordingly, 212,832 shares of common stock remain available for issuance under the Plan. In accordance with the terms of the Plan, if a Director’s participation as a member of the Board ceases or is terminated for any reason prior to the date the shares of restricted stock are fully vested, the unvested portion of the restricted stock shall be automatically forfeited and shall revert back to the Company. The aggregate number of restricted stock awards outstanding and subject to vesting at the fiscal year ended March 31, 2010, for each director was as follows: Robertson – 76,484 shares; and Rodgers – 76,484. In addition, each director was granted 43,584 shares of restricted stock on April 1, 2010, subject to vesting and forfeiture.

Purchases of Equity Securities
The following table summarizes monthly stock repurchase activity for the fourth quarter for the fiscal year ended March 31, 2010:

  
Total Number of Shares Purchased 
(1)
  Average Price Paid Per Share  
Number of Shares Purchased as Part of a Publicly Announced Plan
(1)
  
Maximum Shares that May Yet be Purchased under the Plan
(1)
 
                 
January 1, 2010 - January 31, 2010  9,415  $0.84   9,415   1,207,570 
February 1, 2010 - February 28, 2010  400  $0.80   400   1,207,170 
March 1, 2010 - March 31, 2010  2,800  $0.85   2,800   1,204,370 
                 
Total  12,615       12,615     

(1)On October 22, 2008, the Company’s Board of Directors authorized a stock buyback program for the Company to repurchase up to 500,000 shares of its common stock.stock for a period of up to 18 months. The program does not have a specified expiration date, it does not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time.  On November 13, 2009, the board of directors increased the number of shares authorized for repurchase to 1,500,000.  On February 10, 2010, the board extended the termination date of the program from April 22, 2010 to October 22, 2011.  During the year ended March 31, 2009, 30,2002010, 265,430 shares (rounded to 31,000 in the Statement of Stockholder’s Equity) were repurchased under the stock buyback program and 469,8001,204,370 shares remain available for future repurchase.

12



SELECTED FINANCIAL DATA

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


MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND PLANRESULTS OF OPERATIONOPERATIONS

The following discussion and analysis should be read in conjunction with our financial statements and related notes and the other information appearing in this report. As used in this report, unless the context otherwise indicates, references to “we,” “our,” “ours,” and “us” refer to Earthstone Energy, Inc. and its subsidiary collectively.

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, 2009.2010.

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 agreementfacility to December 31, 2010.

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. The loan agreement has covenants requiring us to maintain a debt-to-equity ratio of less than one and 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, 2010.

During the years ended March 31, 20092010 and 2008,2009, 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, 20092010 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.opportunities. See Note 6 to the Consolidated Financial Statements for a more detailed discussion of our bank credit facility.

Hedging. During 20092010 and 2008,2009, 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.

13



Working Capital. At March 31, 2009,2010, we had a working capital surplus of $5,045,000$5,062,000 (a current ratio of 4.62:3.53:1) compared to a working capital surplus at March 31, 20082009 of $3,168,000$5,045,000 (a current ratio of 1.79:4.62:1).

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%7.2% from $3,609,000 in 2008 to $2,872,000 in 2009.2009 to $2,666,000 in 2010. Net cash used in investing activities increased 654.4%decreased 62.2% from $575,000 in 2008 to $4,338,000 in 2009 to $1,641,000 in 2010, 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 purchase of treasury shares net of proceeds from the exercise of the remaining stock options outstanding, andwhile cash used in financing activities was $208,000 in 2010 for the purchase of treasury shares.

Capital Expenditures. During 20092010 our capital expenditures were primarily focused on properties in the Williston Basin of Montana and North Dakota and in the DJ Basin of Colorado.Dakota. On an accrual basis, total capital expenditures during 20092010 for oil and gas property and equipment and various leasehold interests were $2,177,000.$2,156,000. Of these expenditures, $1,607,000 (74%$1,887,000 (87.5%) areis 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.area.  These projects were funded entirely with internally generated cash flow. See also theAreas of FocusandCompany Developmentssections 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 20092010 and incurred some additional costs pertaining to the abandonment of wells that were pluggedare in prior periods.the process of being plugged.

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).


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.

  Years Ended 
  March 31, 
  2010  2009  2008 
          
Sales volume         
     Oil (barrels)  98,865   92,657   89,400 
     Gas (mcf) 1
  228,575   175,413   108,600 
             
Revenue            
     Oil $6,223,000  $7,406,000  $6,748,000 
     Gas  996,000   1,585,000   667,000 
Total revenue 2
  7,219,000   8,991,000   7,415,000 
             
Total production expense 3
  2,935,000   3,183,000   2,706,000 
             
Gross profit $4,284,000  $5,808,000  $4,709,000 
             
Depletion expense $1,185,000  $1,188,000  $673,000 
             
Average sales price 4
            
     Oil (per barrel) $62.94  $79.93  $75.47 
     Gas (per mcf) $4.36  $9.04  $6.13 
             
Average per BOE            
     Production expense 3,4,5
 $21.43  $26.09  $19.27 
     Gross profit 4,5
 $31.28  $47.61  $43.96 
     Depletion expense 4,5
 $8.65  $9.74  $5.59 

1
Due to the timing and accuracy of sales information received from a third party operator as described in “Volumes and Prices” above, sales volume amounts may not be indicative of actual production or future performance.
2
Amount does not include water service and disposal revenue.  For the year ended March 31, 2010 this revenue amount is net of $50,000 in water service and disposal revenue, which would otherwise total $7,269,000 in revenue for the year ended March 31, 2010, compared to $95,000 and $32,000 to total $9,086,000 and $7,447,000 for the same periods in 2009 and 2008 respectively.
3
Overall lifting cost (oil and gas production expenses and production taxes)
4
Averages calculated based upon non-rounded figures
5Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)
Fiscal 20092010 Compared with Fiscal 20082009

Overview. Net income for the year ended March 31, 20092010 was $578,000$1,028,000 compared to net income of $1,763,000$578,000 for the year ended March 31, 2008,2009, a 67.2% decrease. Earnings for77.9% increase.  This increase is more a function of depressed income in 2009 would have increased if not for anrather than results in 2010.  Net income in 2009 was adversely impacted by a sizeable impairment expense due to oura significant decline in oil and gas property, as well as an increaseprices during the third quarter of 2009.  With rising prices in depletion expense. Production2010, a similar expense was not incurred in the current year.  While oil and gas sales volume increased in 2010, these increases were partially offset by decreased average commodity prices when compared to 2009.  While overall production expenses anddecreased during 2010, general and administrative also increased during the year.increased.


Revenues. Oil and gas sales revenue increased $1,576,000 (21.3%decreased $1,772,000 (19.7%) in 20092010 over 20082009 as a result of overall higherlower average oil and gas prices despite increased oil and increased gas production. Oil sales revenue decreased $1,183,000 (16.0%) and Gas sales revenue alone increased $918,000 (137.6%decreased $589,000 (37.2%) in 20092010 from 2008, while oil sales revenue increased $658,000 (9.8%).2009.

14



Volumes and Prices.  Oil sales volumes increased 3.6%6.7% from 89,400 barrels in 2008 to 92,657 barrels in 2009 to 98,865 barrels in 2010, while the average price per barrel increased 5.9%decreased 21.2% from $75.47 in 2008 to $79.93 in 2009.2009 to $62.94 in 2010. Gas sales volume increased 61.5%30.3% from 108.6175.4 million cubic feet (MMcf) in 20082009 to 175.4228.6 MMcf in 2009.2010.  The average price per Mcf also increased 47.4%decreased 51.8%, from $6.13 in 2008 to $9.04 in 2009.2009 to $4.36 in 2010. The production increase in gas in 20092010 was primarily due to adjustments made during the year, to our revenues, sales volumes, sales prices and severance taxes following the receipt of higher production and sales volume information related to the Antenna Federal wells being temporarily shutproperty in during 2008Weld County, Colorado.  Most of the Company’s gas sales are from our non-operated interest in the Antenna Federal property in Weld County, Colorado.  During the prior year, the Company had estimated gas sales on this property based on the information available at the time and the Company’s experience in the area.  During 2010, we received actual sales volumes and related information from the operator, which were significantly higher than the sales volumes and related information previously reported to, and accrued by, the Company in the prior year.  The incorporation of this information resulted in higher sales volumes, sales prices and severance taxes for the rebuildingcurrent year.   Due to the adjustments made during 2010, for updated sales volumes and related information received from the operator of tank batteries and the completion of new Antenna Federal wells during 2009.property, the higher sales volumes for 2010, are not representative of actual sales volume for this year and should not be used to predict future production or sales volumes.  In addition, production taxes as a percentage of sales, general and administrative expenses as a percentage of sales and any metric whose denominator is related to sales volumes is likely understated. On an equivalent barrel (BOE) basis, sales increased 13%12.3% from 108,000 BOE in 2008 to 122,000 BOE in 2009.2009 to 136,961 BOE in 2010.

Expenses. Oil and gas production expense increased $454,000 (21.8%decreased $102,000 (4.0%) in 20092010 over 2008.2009. 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%$16,000 (0.8%) from $1,602,000 in 2008 to $1,969,000 in 2009 to $1,985,000 in 2010, which is duerelatively comparable. Workover expense decreased $118,000 (20.7%) from $570,000 in large part2009 to expenses incurred from our new$452,000 in 2010 related to an overall decrease in workovers of various wells primarily located 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 workoversbasin of the Whiskey Joe FederalMontana and Beicegal Carson wells in North Dakota. On an equivalent barrel basis, routine lease operating expense increased 8.8%decreased 10.2% from $14.84$16.14 per BOE in 20082009 to $16.14$14.49 in 2009,2010, while workover expense decreased 4.5%29.4% from $4.89$4.67 in 20082009 to $4.67$3.30 per BOE in 2009.2010.

Production taxes, which are a function of sales revenue, increased $23,000 (3.7%decreased $146,000 (22.7%) in 2009 over 2008.2010 from 2009. Production taxes as a percent of oil and gas sales revenue decreased from 8.3% in 2008 to 7.1% in 2009.2009 to 6.9% in 2010.

The overall lifting cost (oil and gas production expense plus production taxes) per BOE was $21.43 in 2010 compared to $26.09 in 2009 compared2009. The decrease primarily related to $24.86the decrease in 2008.production taxes as described in the preceding paragraph.  This lifting 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 and depletion and amortization expense increased $539,000 (78.7%decreased $3,000 (0.2%) in 2009 over 2008. This increase was created by a drop in oil2010 from 2009.  Depreciation 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 increaseddecreased from $6.34 in 2008 to $10.03 in 2009.2009 to $8.91 in 2010.

Accretion of asset retirement obligation decreased $16,000 (14%increased $68,000 (69.4%) in 20092010 from 2008.2009. This decreaseincrease is in part a result of new well additions during the year and revisions to the estimated lives of some of our wells sharing the same leased acreage. Additional information concerning SFAS No. 143asset retirement obligations and related activity during 20092010 can be found in Note 5 to the Consolidated Financial Statements.

Impairment of oil and gas properties occurred during the prior year as a result of the decline in oil and gas prices.  Like mosta number of companies in our industry, 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, 2008.2010.

15



General and administrative (G&A) expense increased $631,000 (88.1%$432,000 (32.1%) in 20092010 over 2008.2009. This increase was primarily due to consulting fees in connection with investor relations and SEC reporting requirements, bad debt expense, professionallegal fees (legal),and related proxy and shareholder expenses and increased rent expense, increases in employees and employee compensation and consulting fees in connection with Sarbanes-Oxley implementation and reporting.executive compensation.  The percentage of G&A expense that was chargedbilled out to operated properties was 11.7% in 2010 compared to 14.4% in 2009 compared to 22% in 2008.2009. G&A expense per BOE increased 85.9%17.6% from $5.94 in 2008 to $11.04 in 2009.2009 to $12.99 in 2010. G&A expense as a percentage of total sales revenue also increased from 9.7% in 2008 to 14.8% in 2009.2009 to 24.5% in 2010.

Other Income/Expense. Due to higher average balances of cash during the prior year,  Interest and other income decreasedincreased from $152,000 in 2008 to $57,000 in 2009.2009 to $90,000 in 2010 due to increases in miscellaneous items. Interest and other expenses increaseddecreased from $28,000 in 2008 to $34,000 in 2009.2009 to $32,000 in 2010.

Income Taxes.In 2009,2010, we recorded income tax expense (benefit) of $(212,000)$148,000 comprised of a current year income tax provision of $346,000,$172,000, and a deferred income tax provision (benefit)benefit of $(558,000).$24,000. This compares to a 20082009 income tax expensebenefit of $1,525,000.$212,000. At March 31, 2008,2009, we had a net deferred tax liabilitybenefit of $1,346,000.$(558,000). Our effective income tax rate decreasedincreased from 46.38% for 2008 to (56.34)% for 2009.2009 to 12.57% for 2010.  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
             
  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 

16


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

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

Oil and Gas Property. We utilize the full cost method of accounting for costs related to our oil and gas property. Capitalized costs included in the full cost pool are depleted on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and may result in lower depreciation and depletion in future periods. The write-down can notcannot 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-eightNinety-three percent of our reported oil and gas reserves at March 31, 20092010 are based on estimates prepared by an independent petroleum engineering firm. The remaining twoseven percent of our oil and gas reserves were prepared in-house. See also Note 12 to the Consolidated Financial Statements.

17



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, “AccountingAs we account for Asset Retirement Obligations” requires thatasset retirement obligations we are required to estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in itsour 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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

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

18



ITEM 8
FINANCIAL STATEMENTS
23
Basic Earth Science Systems, Inc.


FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Earthstone Energy, Inc.
Table of Contents
Consolidated Financial Statements
and Accompanying Notes
March 31, 20092010 and 20082009

19




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

We have audited the accompanying consolidated balance sheetsheets of Basic Earth Science Systems,Earthstone Energy, Inc. and Subsidiaries (the “Company”) as of March 31, 2010 and 2009, and the related statements of operations, shareholders’ equity, and cash flows for the year thenyears ended March 31, 2010 and 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.audits.

We conducted our auditaudits 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 providesaudits provide 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,Earthstone Energy, Inc. as of March 31, 2010 and 2009, and the results of itstheir operations and itstheir cash flows for the yearyears ended March 31, 2010 and 2009 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, as of March 31, 2010, the Company has changed its method of determining quantities of oil and gas reserves which impacted the amount recorded for depreciation and depletion for oil and gas properties.

Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado
June 17, 200918, 2010

20



REPORT OF PRIOR INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
25
To the Board
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

21


Basic Earth Science Systems, Inc.
Consolidated Balance Sheets
        
 March 31, March 31, 
 2009 2008  March 31, March 31, 
  2010 2009 
Assets
      
Current assets:      
Cash and cash equivalents $4,088,000 $5,571,000  $4,905,000  $4,088,000 
Accounts receivable:      
Oil and gas sales 1,611,000 1,110,000   1,021,000   1,611,000 
Joint interest and other receivables, net of $71,000 and $50,000 in allowance, respectively 230,000 236,000 
Joint interest and other receivables, net of $86,000 and $71,000
in allowance for bad debt, respectively
  401,000   230,000 
Other current assets 508,000 280,000   732,000   508,000 
     
      
Total current assets 6,437,000 7,197,000   7,059,000   6,437,000 
      
Oil and gas property, full cost method:      
Proved property 32,187,000 29,050,000   33,915,000   32,187,000 
Unproved property 1,077,000 2,515,000   1,555,000   1,077,000 
Accumulated depletion and impairment  (22,397,000)  (18,515,000)  (23,582,000)  (22,397,000)
          
 
Net oil and gas property 10,867,000 13,050,000   11,888,000   10,867,000 
          
 
Support equipment and other non-current assets, net of $337,000 and $299,000 in accumulated depreciation, respectively 458,000 443,000 
     
Support equipment and other non-current assets, net of $374,000 and $337,000
in accumulated depreciation, respectively
  451,000   458,000 
      
Total non-current assets 11,325,000 13,493,000   12,339,000   11,325,000 
      
Total assets
 $17,762,000 $20,690,000  $19,398,000  $17,762,000 
     

See accompanying notes to consolidated financial statements.

22



Basic Earth Science Systems,
26

Earthstone Energy, Inc.
Consolidated Balance Sheets
         March 31, March 31, 
 March 31, March 31,  2010 2009 
 2009 2008 
 
Liabilities and Shareholders’ Equity
 
Liabilities and Shareholders' Equity     
Current liabilities:      
Accounts payable $64,000 $1,443,000  $161,000  $64,000 
Accrued liabilities 1,328,000 2,586,000   1,836,000   1,328,000 
     
      
Total current liabilities 1,392,000 4,029,000   1,997,000   1,392,000 
      
Long-term liabilities:      
Deferred tax liability 2,242,000 2,800,000   2,217,000   2,242,000 
Asset retirement obligation 1,558,000 1,877,000   1,674,000   1,558,000 
          
 
Total long-term liabilities 3,800,000 4,677,000   3,891,000   3,800,000 
      
Total liabilities 5,192,000 8,706,000   5,888,000   5,192,000 
          
 
Commitments (Note 7) 
Commitments      
      
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 
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 17,704,000 and 17,506,000
shares issued and outstanding, respectively
  18,000   18,000 
Additional paid-in capital 22,825,000 22,798,000   22,945,000   22,825,000 
Treasury stock (380,000 shares); at cost  (43,000)  (23,000)
Treasury stock (646,000 and 380,000 shares respectively) at cost  (251,000)  (43,000)
Accumulated deficit  (10,230,000)  (10,808,000)  (9,202,000)  (10,230,000)
     
      
Total shareholders’ equity 12,570,000 11,984,000   13,510,000   12,570,000 
      
Total liabilities and shareholders’ equity
 $17,762,000 $20,690,000  $19,398,000  $17,762,000 
     

See accompanying notes to consolidated financial statements.

23




Basic Earth Science Systems,
27


Consolidated Statements of Operations
        
 Years Ended  Year Ended 
 March 31,   March 31, 
 2009 2008   2010  2009 
      
Revenues:
      
Oil and gas sales $8,991,000 $7,415,000  $7,219,000 $8,991,000 
Well service and water disposal revenue 95,000 32,000   50,000  95,000 
          
 
Total revenues 9,086,000 7,447,000   7,269,000  9,086,000 
     
      
Expenses:
      
Oil and gas production 2,539,000 2,085,000  2,437,000 2,539,000 
Production tax 644,000 621,000  498,000 644,000 
Well servicing expenses 33,000 27,000  43,000 33,000 
Depreciation and depletion 1,224,000 685,000  1,221,000 1,224,000 
Accretion of asset retirement obligation 98,000 114,000  166,000 98,000 
Asset retirement expense 164,000 35,000  7,000 164,000 
Impairment of oil and gas property 2,694,000  
Impairment of oil and gas properties  2,694,000 
General and administrative 1,347,000 716,000   1,779,000  1,347,000 
     
      
Total expenses 8,743,000 4,283,000   6,151,000  8,743,000 
          
 
Income from operations 343,000 3,164,000   1,118,000  343,000 
     
      
Other Income (Expense):
      
Interest and other income 57,000 152,000  90,000 57,000 
Interest and other expenses  (34,000)  (28,000)  (32,000)  (34,000) 
          
 
Total other income 23,000 124,000   58,000  23,000 
     
      
Income before income taxes 366,000 3,288,000   1,176,000  366,000 
          
Current income tax expense 172,000 346,000 
Deferred income taxes (benefit)  (24,000)  (558,000) 
      
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 
     
Total income tax expense (benefit)  148,000  (212,000) 
      
Net income
 $578,000 $1,763,000  $1,028,000 $578,000 
          
 
Per share amounts:
      
Basic $0.03 $0.10  $0.06 $0.03 
     
Diluted $0.03 $0.10  $0.06 $0.03 
     
      
Weighted average common shares outstanding:      
Basic 17,477,216 17,370,256   17,073,526  17,105,352 
     
Diluted 17,477,216 17,480,671   17,073,526  17,105,352 
     

See accompanying notes to consolidated financial statements.

24


Basic Earth Science Systems,
28


Consolidated Statements of Shareholders’ Equity
Years Ended March 31, 20092010 and 20082009
                                 Additional         
 Additional        Common stock paid-in Treasury stock Accumulated   
 Common stock paid-in Treasury stock Accumulated    Shares Amount capital Shares Amount deficit Total 
 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 
               
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 directors           15,000            24,000              24,000 
Stock options exercised 165,000  49,000    49,000            25,000      1,000             3,000                4,000 
Net income      1,763,000 1,763,000                       578,000          578,000 
                              
 
Balance, March 31, 2008
 17,466,000 $17,000 $22,798,000  (349,000) $(23,000) $(10,808,000) $11,984,000 
               
March 31, 2009     17,506,000 $   18,000 $   22,825,000     (380,000) $     (43,000) $   (10,230,000) $   12,570,000 
                
Purchase of treasury shares     (31,000)  (20,000)   (20,000)       (266,000)    (208,000)         (208,000) 
Shares issued to independent board members 15,000  24,000    24,000 
Stock options exercised 25,000 1,000 3,000    4,000 
Shares issued to independent directors         192,000          120,000            120,000 
Shares issued to employees             6,000              —                — 
Net income      578,000 578,000                    1,028,000       1,028,000 
                              
 
Balance, March 31, 2009
 17,506,000 $18,000 $22,825,000  (380,000) $(43,000) $(10,230,000) $12,570,000 
               
March 31, 2010     17,704,000 $   18,000 $   22,945,000     (646,000) $   (251,000) $     (9,202,000) $   13,510,000 

See accompanying notes to consolidated financial statements.

25




Basic Earth Science Systems,
29


Consolidated Statements of Cash Flows
        
 Years Ended  Year Ended 
 March 31,   March 31, 
 2009 2008   2010  2009 
      
Cash flows from operating activities:
      
Net income $578,000 $1,763,000  $         1,028,000 $            578,000 
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and depletion 1,224,000 685,000           1,221,000          1,224,000 
Deferred tax liability  (558,000) 1,311,000              (24,000)           (558,000) 
Additional paid-in capital associated with deferred tax expense  35,000 
Accretion of asset retirement obligation 98,000 114,000              166,000               98,000 
Share based compensation 24,000                 72,000               24,000 
Impairment of Oil and Gas Properties 2,694,000  
Impairment of oil and gas properties  ―          2,694,000 
Change in:      
Accounts receivable, net  (495,000)  (85,000)             419,000           (495,000) 
Other assets  (287,000)  (63,000)           (224,000)           (287,000) 
Accounts payable and accrued liabilities  (406,000)  (158,000)                8,000            (406,000) 
Other  7,000 
     
      
Net cash provided by operating activities
 2,872,000 3,609,000            2,666,000           2,872,000 
     
      
Cash flows from investing activities:
      
Oil and gas property  (4,338,000)  (587,000)        (1,612,000)        (4,338,000) 
Support equipment   (16,000)              (29,000)   ― 
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)         (1,641,000)         (4,338,000) 
     
      
Cash flows from financing activities:
      
Proceeds from exercise of common stock options 3,000 14,000   ―                 3,000 
Purchase of treasury shares  (20,000)              (208,000)              (20,000) 
          
 
Net cash (used in) provided by financing activities
  (17,000) 14,000 
     
Net cash used in financing activities            (208,000)              (17,000) 
      
Cash and cash equivalents:
      
(Decrease) increase in cash and cash equivalents  (1,483,000) 3,048,000 
Increase (decrease) in cash and cash equivalents              817,000         (1,483,000) 
Balance, beginning of year 5,571,000 2,523,000            4,088,000           5,571,000 
     
      
Balance, end of period
 $4,088,000 $5,571,000  $         4,905,000 $         4,088,000 
          
 
Supplemental disclosure of cash flow information:
      
Cash paid for interest $10,000 $28,000  $              17,000 $              10,000 
     
Cash paid for income tax $517,000 $171,000  $                6,500 $            517,000 
     
 
Non-cash:      
Increase in oil and gas property due to asset retirement obligation $33,000 $210,000  $              54,000 $            33,000 
     
Vested shares issued as compensation $              48,000 $              24,000 
Additions to oil and gas also included in accrued liabilities $43,000 $2,273,000  $         687,000 $              43,000 
     

See accompanying notes to consolidated financial statements.

26



Basic Earth Science Systems,
30


Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Organization and Nature of Operations. Basic Earth Science Systems,Earthstone Energy, Inc. (“Basic”Earthstone” or “the Company” or “we” or “our” or “us”), was originally organized in July 1969 and had its first public offeringas Basic Earth Science Systems, Inc.  We changed our name in 1980.2010 to Earthstone Energy, Inc. 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 ActivityProperties.  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, with the exception of unproved properties which are periodically reviewed for impairment by reviewing the status of the activity on those properties and surrounding properties either held by us or other parties. 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 pricesthe 12 month average price of oil and gas on the first day of each month 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, 2008,2010, 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$8.65 and $6.34$9.74 for 20092010 and 2008,2009, respectively.

Income Taxes.  We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”FASB issued authoritative guidance 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.

27



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 2009the years ended March 31, 2010 and 2008:2009:
         
  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
   2010   2009 
Numerator:        
     Net income available to common shareholders $1,028,000  $578,000 
         
Denominator:        
     Denominator for basic earnings per share  17,073,526   17,105,352 
Effect of dilutive securities:        
     Stock options      
         
Denominator for diluted earnings per share  17,073,526   17,105,352 

There were no options issued andor outstanding were included in the computation of diluted earnings per share for 2008, and were not applicable for2010 or 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 and cash equivalents, 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 20092010 and 2008.2009. 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 forFASB issued authoritative guidance to long-lived assets not included in oil and gas properties.  Under the Impairment or Disposal of Long-Lived Assets” in evaluatingguidance, all long-lived assets exceptare tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable.  The carrying amount of a long-lived asset is not recoverable if it exceeds the full cost pool for possible impairment. Under SFAS No. 144,sum of the undiscounted cash flows expected to result from its use and eventual disposition.  An impairment loss is recognized when the carrying value of a long-lived assets are reported at the lowerasset is not recoverable and exceeds its fair value.

Major Customersand Concentration of Credit Risk.Purchasers of 10% or more of our oil and gas production revenue forreceived at March 31, 2010 and 2009 and 2008 are as follows:
          2010  2009 
 2009 2008      
 
Murphy Oil USA, Inc.  25%  22%
Valero Energy  17%  20% 16% 17% 
Nexen Marketing USA, Inc.  14%  11% 10% 14% 
Murphy Oil USA, Inc. 8% 25% 
Plains Inc.  14%  15%    14% 
Texon LP  6%  10%
     
      
Total  76%  78%  34%  70% 
     

It is not expected that the loss of any one of these customerspurchasers would cause a material adverse impact on our operations sincebecause alternative markets for our products are readily available.
In the year ended March 31, 2010, approximately 57% of our oil and gas revenue was received from non-operated properties where we have no control over the selection of the purchaser.  On these properties our portion of the product was marketed on our behalf by the 21 different companies who operate these wells.  These 21 companies may, unbeknownst to us, market to one or more of the same purchasers that we use.  Therefore, we are unable to ascertain the total extent of combined purchaser concentration.  To the extent of our knowledge, in the event of the bankruptcy of any one of our purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%.

Stock Option Plan. With the issuance of SFAS No. 123(R), Accounting for Share Based Compensation, effective December 2004, weWe 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 20092010 or 2008.2009. 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 beenwere reclassified to conform to current year presentation. Such reclassifications had no effect on the prior year net income.

Recent Accounting Pronouncements

In June 2009, the FASB issued Accounting Standards Codification, “Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Codification”) which will become the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative.  This Statement is effective for financial statements issued for interim and annual periods ended after September 15, 2009.  The adoption of the Codification did not have a material impact on our consolidated financial statements or results of operations.

In June 2009, the FASB issued guidance related to subsequent events which incorporates the guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. In February 2010, the FASB issued an update to this guidance which no longer requires the Company to disclose the date through which subsequent events have been evaluated. We adopted this update which had no impact on the Company’s consolidated financial statements or results of operations.

On April 29, 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSPguidance related to financial instruments, which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to requirerequires 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 107-1statements, and APB 28-1 areis effective for interim periods endingended after June 15, 2009. The adoption of FSP SFAS 107-1 isWe have adopted these new provisions, which did not expected to have a material impact on the Company’s consolidated financial statements or results of operations.

29


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. 141Rguidance related to addressbusiness combinations, which addresses 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-1combination, including the treatment of contingent consideration, acquisition costs, research and development assets and restructuring costs. In addition, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. The new guidance 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 new 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 first-day-of-the-month price during the prior 12-month period, rather than year-end prices, and allow companies to disclose their probable and possible reserves to investors.prices. The new rules are expected to be effective for years ending on or after December 31, 2009. The adoption of the new rules is considered a change in accounting principle inseparable from a change in accounting estimate. The Company isdoes not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or financial statements which also impact the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new guidance, subsequent price increases cannot be considered in the process of evaluatingceiling test calculation. The Company does not believe that it is practicable to estimate the effect of theseapplying the new requirements,rules on net loss or the amounts recorded for depreciation, depletion and has not yet determinedamortization and ceiling impairment for the impact that it will have on its financial statements upon full adoption onyear ended 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.

30


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 157guidance related to fair value measurements and disclosures, which 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 157The new guidance 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. 157the new guidance with the one-year deferral for non-financial assets and liabilities. The adoption of SFAS No. 157the new guidance did not have a material impact on our financial position, results of operations or cash flows. Beginning April 1, 2009, we expect to adopthave adopted 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 thatThe adoption willdid not have a material impact on our financial statements.

31



2. Other Current Assets

Other current assets at March 31, 20092010 and 20082009 consisted of the following:
        
 2009 2008   2010  2009 
      
Lease and well equipment inventory $170,000 $154,000  $399,000 $170,000 
Drilling and completion cost prepayments 149,000 52,000  244,000 149,000 
Prepaid insurance premiums 44,000 58,000  49,000 44,000 
Other current assets 145,000 16,000   40,000  145,000 
          
 
Total other current assets $508,000 $280,000  $732,000 $508,000 
     

The lease and well equipment inventory included in Other Current Assets 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, 20092010 and 20082009 consisted of the following:
          2010  2009 
 2009 2008      
 
Lease and well equipment inventory $261,000 $250,000 
Support equipment and lease and well equipment inventory $272,000 $261,000 
Plugging bonds 60,000 69,000  60,000 60,000 
Other non-current assets 137,000 124,000   119,000  137,000 
          
 
Total other non-current assets $458,000 $443,000 
     
Total support equipment and other non-current assets $451,000 $458,000 

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.

32



4. Accrued Liabilities

Accrued liabilities atfor the years ended  March 31, 20092010 and 20082009 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 
       

   2010   2009 
         
Revenue and production taxes payable $348,000  $532,000 
Accrued compensation  172,000   288,000 
Accrued operations payable  820,000   225,000 
Accrued taxes payable and other  396,000   143,000 
Short term asset retirement obligation  100,000   140,000 
         
 Total $1,836,000  $1,328,000 

5. Asset Retirement Obligation
SFAS No. 143, “Accounting for Asset Retirement Obligations” requires
We recognize 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 theseThese 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 2009the years ended March 31, 2010 and 2008:2009:
        
 Years Ended 
 March 31, 
 2009 2008   2010  2009 
      
Asset retirement obligation at beginning of period $2,179,000 $1,971,000  $1,698,000 $2,179,000 
Liabilities settled during the period  (168,000)  (116,000) (134,000) (168,000) 
New obligations for wells drilled and completed 33,000 84,000  54,000 33,000 
Accretion of asset retirement obligation 98,000 114,000  166,000 98,000 
Revisions to estimates  (444,000) 126,000   (10,000)  (444,000) 
          
 
Asset retirement obligation at end of period $1,698,000 $2,179,000  $1,774,000 $1,698,000 
          
 
Current accrued liability $140,000 $302,000 
Current liability $100,000 $140,000 
Long-term liability 1,558,000 1,877,000   1,674,000  1,558,000 
          
 
Asset retirement obligation at end of each period $1,698,000 $2,179,000  $1,774,000 $1,698,000 
     

Asset retirement expense as recorded in the years ended March 31, 20092010 and 20082009 represents plugging and abandonment costs in excess of the estimated asset retirement obligation recorded with the adoption of SFAS No. 143.recorded. We based our initial estimates on our knowledge and experience plugging wells in earlier years.

33



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, 2009.2010.

This credit line is collateralized by a significant portion of our oil and gas properties and production, and as of March 31, 2009,2010, 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 base rent payments of approximately $5,685$5,853 per month escalating at a rate of approximately $170 at the end of each year. Office rent expense was approximately $87,000$107,000 in 20092010 (including building maintenance charges), and $36,000$87,000 in 2008.2009.  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).2009.

34


A summary of the status of our stock option plan and outstanding options as of March 31, 20092010 and 2008,2009, and changes during the years endingended on those dates is presented below:
                
 2009 2008  2010  2009 
 Weighted Weighted    Weighted   Weighted 
 Average Average    Average   Average 
 Exercise Exercise    Exercise   Exercise 
 Shares Price Shares Price  Shares Price Shares Price 
                 
Options unexercised, beginning of year 25,000 $0.1325 190,000 $0.0936     $   25,000  $0.1325 
          
Granted                 
Cancelled                 
Exercised  (25,000)  (0.1325)  (165,000)  (0.0941)        (25,000)  (0.1325)
                  
 
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 related to stock options 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 for the years ended March 31, 2010 and 2009 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 
       

35

  2010  2009 
Current:      
  Federal $171,000  $305,000 
  State  1,000   41,000 
 Total current income tax expense  172,000   346,000 
         
Deferred:        
  Federal  (23,000)  (483,000)
  State  (1,000)  (75,000)
Total deferred income tax expense (benefit)  (24,000)  (558,000)
         
Income tax expense (benefit) $148,000  $(212,000)

A reconciliation between the income tax provision at the statutory rate on income taxes and the income tax provision for the years ended March 31, 2010 and 2009 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 
       
  2010  2009 
         
Federal taxes at statutory rate $400,000  $124,000 
State taxes, net of federal benefit  9,000   (18,000)
Excess percentage depletion  (283,000)  (322,000)
Other adjustments  22,000   4,000 
         
Income tax expense (benefit) $148,000  $(212,000)

The components of the net deferred tax assets and liabilities for the years ended March 31, 2010 and 2009 are shown below:as follows:
         2010 2009 
 For the Years Ended 
 March 31, 
 2009 2008 
 
Deferred tax assets:     
Allowance for doubtful accounts $26,000 $20,000  $31,000  $26,000 
Asset retirement obligation 633,000 850,000   647,000   633,000 
Other accruals  (4,000) 112,000 
Statutory depletion carryforward 858,000 1,043,000   1,074,000   858,000 
             
Gross deferred tax assets  1,752,000   1,517,000 
      
Total gross deferred tax assets 1,513,000 2,025,000 
Other accruals  47,000   (4,000)
Depreciation, depletion and intangible drilling costs  (4,016,000)  (3,755,000)
             
Gross deferred tax liabilities  (3,969,000)  (3,759,000)
      
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)
     
Deferred tax assets (liabilities), net $(2,217,000) $(2,242,000)

We follow authoritative guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements. Tax positions must meet a “more-likely-than-not” recognition threshold before a benefit is recognized in the financial statements.  As of March 31, 2009, we had fully utilized our net operating loss carry-forward2010, the Company has not recorded a liability for uncertain tax purposes. We have statutory depletion carryforwards of $2,300,000 that do not expire.
positions. The adoption of FIN 48 had no impact on our consolidated financial statements. We are subjectCompany recognizes interest and penalties related to U.S. federaluncertain tax positions in income tax expense. No interest and incomepenalties related to uncertain tax from multiple state jurisdictions.positions were accrued at March 31, 2010.  The tax years remaining subject to examination by tax authorities are fiscal years 20042005 through 2008. We recognize interest and penalties related to uncertain tax positions in income tax expense. As2009.

10. Related Party Transactions

It is our policy that officers or directors may assign to us or receive assignments from us in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. It is also our policy that officers or directors and the Company may participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by each other.non-related third parties. In 2010, Ray Singleton, President of the Company, participated in the drilling of the Crown 41-31  in Sheridan County, Montana on the same terms and conditions as other third parties.  The well resulted in a dry hole.  During 20092010 and 20082009, none of our officersother directors or directorsofficer participated with the Company in any of our oil and gas transactions. In prior years, RayMr. Singleton President of the Company, has participated with us in certain acquisitions.the acquisition of producing properties on the same terms and conditions as the Company and other third parties. As such, Mr. Singleton paid for his proportionate share of the acquisition costs at the time of the acquisition.  With respect to his working interest in the four producing wells in which he currently participates,has an ownership, at March 31, 20092010, the Company had a balance due fromto Mr. Singleton for less than $1,000approximately $10,000 compared to a payable balance due tofrom him of approximately $2,000less than $1,000 at March 31, 2008.2009. This was due to his share of operating expensesoil and gas revenue exceeding the amount due tofrom him for his share of oil and gas revenueoperating expenses from these wells.

11. Oil and Gas Property

The aggregate amount of capitalized costs related to oil and gas properties and the aggregate amount of related accumulated depreciation and depletion at March 31, 20092010 and 20082009 are as follows:
        
 2009 2008   2010  2009 
     
Proved property $32,187,000 $29,050,000  $33,915,000 $32,187,000 
Unproved property 1,077,000 2,515,000   1,555,000  1,077,000 
          
  35,470,000 33,264,000 
Gross oil and gas property 33,264,000 31,565,000 
Accumulated depletion and impairment  (22,397,000)  (18,515,000)  (23,582,000)  (22,397,000) 
          
 
Net oil and gas property $10,867,000 $13,050,000 
     
Net capitalized oil and gas property $11,888,000 $10,867,000 

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

Williston Basin.  Five new wells in the Williston Basin primarily within McKenzie County, North Dakota represent $763,000 for 49.1% of the total unproved property costs.  These wells will be removed from the unproved property classification upon evaluation.

Banks ProspectField.  The Banks ProspectField represents approximately 55.3%20.5% of total unproved property costs, $596,000,$318,000, associated with a 13,000 gross acre horizontal Bakken play in McKenzie County, North Dakota. For further information seeAreas of Focusof Item 1. “Description of Business.”

Christmas Meadows.  The Christmas Meadows prospect consists of approximately 36.8%25.5% of total unproved property costs, $396,000, related to 40,000+ acres operated by Double Eagle Petroleum Company (Double Eagle). For further information seeAreasCompany.

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

37


The following table shows, by category and date incurred, the oil and gas property costs applicable to unproved property that were excluded from the depreciation and depletion computation at March 31, 2009:2010:
                
 Total 
Costs Incurred During Exploration Development Acquisition Unproved  Exploration Development Acquisition Total Unproved 
Year Ended Costs Costs Costs Property  Costs Costs Costs Property 
                 
March 31, 2010 $1,000  $791,000  $  $792,000 
March 31, 2009 $249,000 $ $ $249,000   249,000         249,000 
March 31, 2008 29,000   29,000   29,000         29,000 
March 31, 2007 308,000   308,000   308,000         308,000 
March 31, 2006 428,000 39,000  467,000   134,000   39,000      173,000 
March 31, 2005 24,000   24,000   4,000         4,000 
                         
 
Total $1,038,000 $39,000 $ $1,077,000  $725,000  $830,000  $  $1,555,000 
         

Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 20092010 and 20082009 are summarized as follows:
         
  For the Years Ended 
  March 31, 
  2009  2008 
         
Development costs $2,177,000  $2,410,000 
Exploration costs     40,000 
Acquisitions:        
Proved     250,000 
Unproved      
       
         
Total $2,177,000  $2,700,000 
       
   2010   2009 
         
Development costs $1,536,000  $2,177,000 
Exploration costs  620,000    
Acquisitions:        
     Proved      
     Unproved      
         
Total $2,156,000  $2,177,000 

12. Unaudited Oil and Gas Reserves Information

At March 31, 2010 and 2009, 93% and 2008, 98% and 93% respectively, of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company. The remaining 27% and 7 percent2% of the reserve estimates, respectively, were prepared internally by our management. There are many inherent uncertainties in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available, and these changes could be material.

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

38



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

Proved Reserves
         
  Oil and    
  Natural    
  gas  Natural 
  liquids  gas 
  (Bbls)  (Mcf) 
         
Proved developed reserves at March 31, 2007  995,000   1,138,000 
       
         
Revisions of previous estimates  112,000   (113,000)
Extensions and discoveries  19,000   203,000 
Sales of reserves in place      
Improved recovery  15,000   1,000 
Purchase of reserves  22,000    
Production  (89,000)  (109,000)
       
         
Proved developed reserves at March 31, 2008  1,074,000   1,120,000 
       
         
Revisions of previous estimates  (429,000)  (262,000)
Extensions and discoveries  86,000   253,000 
Sales of reserves in place      
Improved recovery      
Purchase of reserves      
Production  (93,000)  (175,000)
       
         
Proved developed and undeveloped reserves at March 31, 2009  638,000   936,000 
       

As of March 31, 2009, we have proved reserves related to undeveloped property, whereas for March 31, 2008, all of our oil and gas reserves were classified as Proved Developed, Producing.
  March 31, 2010  March 31, 2009  March 31, 2008 
  
Oil
(Bbls)
  
Gas
(Mcf)
  
Oil
(Bbls)
  
Gas
 (Mcf)
  
Oil
(Bbls)
  
Gas
(Mcf)
 
Proved reserves:                        
     Balance, beginning of year  638,000   936,000   1,074,000   1,120,000   995,000   1,138,000 
          Revisions of previous estimates (1)  275,000   195,000   (429,000)   (262,000)   112,000   (113,000) 
          Extensions and discoveries (2)  4,000   10,000   86,000   253,000   19,000   203,000 
          Sales of reserves in place                  
          Improved recovery              15,000   1,000 
          Purchase of reserves              22,000    
          Production (3)  (99,000)   (229,000)   (93,000)   (175,000)   (89,000)   (109,000) 
                         
     Balance, end of year  818,000   912,000   638,000   936,000   1,074,000   1,120,000 
                         
Proved developed reserves:                        
     Balance, beginning of year            587,000   907,000   1,074,000   1,120,000   995,000   1,138,000 
                         
     Balance, end of year  727,000   912,000   587,000   907,000   1,074,000   1,120,000 
                         
Proved undeveloped reserves:                        
     Balance, beginning of year  51,000    29,000    —    —    —    —  
                         
     Balance, end of year  91,000   —    51,000    29,000    —    —  

(1)  Revisions of Previous Estimates – Overall our properties experienced an increase in estimated economic life due to increases in oil and gas prices during the year ended March 31, 2010. Changes in performance constitute less than 10% of the total amount of revisions of previous estimates.

(2)  Extensions and Discoveries – The additions consisted of two new well in wells in Weld County, Colorado and one new well in the Dunn County, North Dakota.

(3)  Production – This change in reserves is due to volumes of oil and gas that was produced and removed from reserves during the year.

The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to our proved oil and gas reserves. Estimated future cash inflows were computed by applying year end (March 31) pricesthe 12 month average price of oil and gas on the first day of each month (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves at March 31, 2010, 2009 and 2008. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

39




Standardized Measure of Estimated Discounted Future Net Cash Flows
        
 For the Years Ended 
 March 31,   
For the Years Ended
March 31,
 
 2009 2008   2010  2009  2008 
           
Future cash inflows $31,793,000 $114,296,000  $55,991,000  $31,793,000 $114,296,000 
Future cash outflows:        
Production cost  (17,924,000)  (49,599,000)  (29,065,000)   (17,924,000) (49,599,000) 
Development cost  (490,000)    (991,000)   (490,000)  
Future income taxes  (2,100,000)  (17,826,000)  (3,361,000)   (2,100,000) (17,826,000) 
            
 
Future net cash flows 11,279,000 46,871,000   22,574,000   11,279,000 46,871,000 
Adjustment to discount future annual net cash flows at 10%  (4,080,000)  (21,911,000)  (10,060,000)   (4,080,000)  (21,911,000) 
            
 
Standardized measure of discounted future net cash flows $7,199,000 $24,960,000  $12,514,000  $7,199,000 $24,960,000 
     

The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for 2010, 2009 and 2008.

Changes in Standardized Measure of Estimated Discounted Net Cash Flows
         
  For the Years Ended 
  March 31, 
  2009  2008 
         
Standardized measure, beginning of period $24,960,000  $14,624,000 
       
Sales of oil and gas, net of production cost  (5,808,000)  (4,727,000)
Net change in sales prices, net of production cost  (25,977,000)  14,598,000 
Discoveries, extensions and improved recoveries, net of future development cost  2,298,000   3,054,000 
Change in future development costs      
Development costs incurred during the period that reduced future development cost      
Sales of reserves in place      
Revisions of quantity estimates  (4,745,000)  2,639,000 
Accretion of discount  4,279,000   1,865,000 
Net change in income taxes  16,594,000   (4,221,000)
Purchase of reserves     361,000 
Changes in timing of rates of production  (4,402,000)  (3,233,000)
       
         
Standardized measure, end of period $7,199,000  $24,960,000 
       

40

   
For the Years Ended
March, 31
 
   2010   2009   2008 
             
Standardized measure, beginning of period $7,199,000  $24,960,000  $14,624,000 
             
     Sales of oil and gas, net of production cost  (4,284,000)   (5,808,000)   (4,727,000) 
     Net change in sales prices, net of production cost  6,279,000   (25,977,000)   14,598,000 
     Discoveries, extensions and improved recoveries, net of future development cost  154,000   2,298,000   3,054,000 
     Change in future development costs  467,000       
     Development costs incurred during the period that reduced future development cost         
     Sales of reserves in place         
     Revisions of quantity estimates  5,280,000   (4,745,000)   2,639,000 
     Accretion of discount  720,000   4,279,000   1,865,000 
     Net change in income taxes  (1,582,000)   16,594,000   (4,221,000) 
     Purchase of reserves        361,000 
     Changes in timing of rates of production  (1,719,000)   (4,402,000)   (3,233,000) 
             
Standardized measure, end of period $12,514,000  $7,199,000  $24,960,000 



CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
As defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act, of 1934 (the “Exchange Act”), the termphrase “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.   Disclosure controls and procedures include without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuerus in the reports that it fileswe file or submitssubmit under the Exchange Act is accumulated and communicated to the issuer’sour management, including its principal executiveour Chief Executive Officer and principal financial officers, or persons performing similar functions,Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
The
We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2010.  This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer. Based on this evaluation, our Chief Executive Officer and Principal Accounting Officer evaluated the effectiveness of the Company’s disclosure controls and procedures and concluded that, following implementationas of the changes in internal control over financial reporting discussed below, the Company’sMarch 31, 2010, our disclosure controls and procedures were effective as of March 31, 2009.effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the year ended March 31, 2009our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’sour internal control over financial reporting.
Management’s
Management's Annual Report on Internal Control Over Financial Reporting

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

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

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

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

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

Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements.  Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
With
Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Principal Accounting Officer, the Company’s managementwe conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework and criteria established inInternal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, the Company’s management concluded that the Company’sCompany's internal control over financial reporting was effective as of March 31, 2009.2010.

Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-K.  Therefore, this Annual Report on Form 10-K does not include such an attestation.
By:/s/ Ray SingletonBy:/s/ Joseph Young
Ray Singleton, President
Joseph Young
Chief Executive OfficerPrincipal Accounting Officer
June 18, 2009June 18, 2009

OTHER INFORMATION
There is no information required to be disclosed on Form 8-K during the fourth quarter
None.

45



Part III
ITEM 10
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors
The following sets forth the names and ages of the members of the Board of Directors of Basic Earth Science Systems, Inc. (“Basic” or “the Company” or “we” or “our” or “us”) who served during the past year, their respective principal occupations or employment during the past five years, and the period during which each has served as a director of the Company.
Ray Singleton(58) has been a director of Basic since July 1989. Mr. Singleton joined the CompanyInformation relating to this item will be included in June 1988 as Production Manager/Petroleum Engineer. In October 1989, he was elected Vice President, and was appointed President and Chief Executive Officer in March 1993. Mr. Singleton began his career with Amoco Production Company in Texas as a production engineer. He was subsequently employed by the predecessor of Union Pacific Resources as a drilling, completion and production engineer and in 1981 began his own engineering consulting firm, serving the needs of some 40 oil and gas companies. As a consultant he was retained by the Company on various projects from 1981an amendment to 1987. Mr. Singleton currently serves on the Board of Directors of the Independent Petroleum Association of Mountain States (IPAMS) and is a former president of that organization. IPAMS is a thirteen-state, regional trade association that represents the interests of independent oil and gas companies in the Rocky Mountain region. In addition, Mr. Singleton is a member of the Society of Petroleum Engineers. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1973 and received a Masters Degree in Business Administration from Colorado State University’s Executive MBA Program in 1992.
Richard K. Rodgers(49) has been a director of Basic since December 2006. Mr. Rodgers was originally appointed to fill the vacancy created by the resignation of a prior director, and was then elected as a director at the Company’s shareholder meeting held on January 15, 2007. For the last three years, Mr. Rodgers has provided business development, planning and financial consulting services to various banking and business development clients. During the past five years, Mr. Rodgers was employed by several Denver area banks including Key Bank, Guaranty Bank & Trust Company and Colorado Capital Bank. In his most recent employment with Colorado Capital Bank from 2004 to 2005, he was the President, and was responsible for the start-up, of its Cherry Creek branch office and served on the Board of Directors of Colorado Capital Bank. Mr. Rodgers attended the University of Denver and received his Bachelor of Science degree in International Business Administration in 1995 and his Master of Science degree in International Business Administration in 1997.
Monroe W. Robertson(59) was originally appointed to fill the vacancy created when the Board, on April 4, 2007, amended the Company’s Bylaws to increase the number of members of the Board from three (3) members to four (4) members. Subsequently, he was elected as a director at the Company’s shareholder meeting held on January 21, 2008. Mr. Robertson currently serves on the Board of Directors of Cimarex Energy Company and is chairman of that board’s Audit Committee. Mr. Robertson began his career in 1973 with Gulf Oil Corporation and held various positions in engineering, corporate planning and financial analysis until 1986. From 1986 to 1992 he held various positions at Terra Resources and Apache Corporation. In 1992 Mr. Robertson joined Key Production Company as its Senior Vice President and Chief Financial Officer. In 1999 he was appointed President and Chief Operating Officer of that company and served in that role until 2002. Other than his service on Cimarex’s board which began in October 2005, for the past five years Mr. Robertson has been a private investor. Mr. Robertson received a Bachelor of Science degree in Mechanical Engineering along with Master of Science degrees in both Mechanical Engineering and Nuclear Engineering from the Massachusetts Institute of Technology in 1973. He also has received a Masters Degree in Business Administration from National University in 1979. Mr. Robertson is a member of the National Association of Corporate Directors.

43


Directors are elected by the Company’s shareholders at each annual meetingthis report or in the case of a vacancy, are appointed by the directors then in office, to serve until the next annual meeting or until their successors are elected and qualified. Officers are appointed by and serve at the discretion of the Board of Directors. There are no family relationships between or among the Board of Directors.
Executive Officers
In February 2008, Mr. Flake resigned as an officer of the Company, and then as a director in October 2008. Prior to this, the Company’s executive officers were Ray Singleton and David Flake. Both were also board members. Subsequent to Mr. Flake’s resignation as an officer, we hired on a contract basis Joseph Young as Principal Accounting Officer. The names, ages, principal occupations and/or employment during the past five years are set forth above for Ray Singleton and below for Joseph Young. There are no family relationships between or among the officers and Board of Directors.
Joseph Young
Joseph Young (30) joined the Company in March 2008 as the Company’s Principal Accounting Officer, subsequent to the resignation of David Flake. Mr. Young began his public accounting career at PricewaterhouseCoopers in the Silicon Valley area, where he audited multiple public and private companies for financial reporting and Sarbanes-Oxley compliance. Since then, he has provided accounting, reporting, and compliance services to a variety of businesses within the oil and gas, mining and technology sectors. Mr. Young previously served as Chief Financial Officer for JayHawk Energy, Inc. and Controller for Fellows Energy, Inc. Mr. Young received his Bachelor of Arts degree in Accounting from the University of Utah in 2002.
Involvement in Certain Legal Proceedings
During the past five years, no present director or executive officer of the Company has been the subject matter of any of the following legal proceedings: (a) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (b) any criminal convictions; (c) any order, judgment, or decree permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or (d) any finding by a court, the SEC or the CFTC to have violated a federal or state securities or commodities law. Further, no such legal proceedings are believed to be contemplated by governmental authorities against any director or executive officer.
Corporate Governance
Independent Directors.Each of the Company’s directors, except for Mr. Singleton, qualifies as an “independent director” as defined under the published listing requirements of the American Stock Exchange. The independence definition includes a series of objective tests. For example, an independent director may not be employed by Basic and may not engage in certain types of business dealings with the Company. In addition, the Board has made a subjective determination as to each independent director that no relationship exists, which in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the Board reviewed and discussed information provided by the directors and by the Company with regard to each director’s business and personal activities as they may relate to the Company and its management. Also, the Board determined that the members of the Audit Committee each qualify as “independent” under special standards established by the American Stock Exchange and the SEC for members of audit committees.

44


Audit Committee.The Board of Directors has a standing Audit Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson. During fiscal 2009 the Audit Committee met eight times. The Audit Committee is authorized to review, with the Company’s independent accountants, the annual financial statements of the Company prior to publication and to make annual recommendations to the Board for the appointment of independent public accountants for the ensuing year. It is the responsibility of the Audit Committee to review the effectiveness of the financial and accounting functions, operations, and internal controls implemented by Basic’s management.
The Board has certified both Mr. Robertson and Mr. Rodgers as financially literate, and Mr. Robertson as an “audit committee financial expert,” as defined under Regulation S-K under the Exchange Act. Both Mr. Robertson and Mr. Rodgers are considered “independent directors” under the listing standards of the American Stock Exchange.
Compensation Committee.The Board of Directors has a standing Compensation Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson, both of whom are independent under the guidelines of the American Stock Exchange listing standards. Mr. Rodgers serves as the Committee’s chairman. The responsibilities of the Compensation Committee (the “Committee”) of the Board of Directors are three-fold: first, establishing and administering the general compensation policies of the Company, second, setting the specific compensation for the Company’s chief executive officer (CEO) and lastly, recommending to the Board of Directors the independent director compensation.
No interlocking relationship exists between the members of the Company’s Board of Directors or Compensation Committee and the board of directors or compensation committee of any other company.
Nominating Committee.The Board of Directors has a standing Nominating Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson.
No material changes have been made to the procedures by which security holders may recommend nominees to the Board of Directors since we filed with the Securities and Exchange Commission, on October 28, 2008, its definitive proxy statement for the 2008 Annual Meeting of Shareholders.our 2010 annual stockholders’ meeting and is incorporated by reference in this report.
Code of Ethics.We have adopted a Code of Ethics as defined in Regulation S-K that applies to our directors, principal executive and financial officer and persons performing similar functions. The Code of Ethics can be found on our website athttp://www.basicearth.net.
Compliance with Section 16(a) of the Securities Exchange Act
Section 16(a) of the Securities Exchange Act requires the Company’s officers and directors and shareholders of more than ten percent of the Company’s common stock to file reports of ownership and changes in ownership of the Company’s common stock with the Securities and Exchange Commission (SEC). Officers and directors are required by SEC regulations to furnish Basic with the information necessary for the Company to file all required Section 16(a) reports. During fiscal 2009 all required reports were filed timely.

45


ITEM 11
EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth the compensation paidInformation relating to this item will be included in an amendment to this report or accrued by the Company to its Chief Executive Officer and Principal Accounting Officer for fiscal 2009 and 2008. No other director, officer or employee received annual compensation that exceeded $100,000.
                         
              Non-Equity  All    
Name and Fiscal  Salary  Bonus  Incentive Plan  Other  Total 
Principal Position Year  ($)  ($)  Compensation  Compensation  ($) 
          (1)  (2)  (3)     
Ray Singleton  2009  $183,574  $29,307  $9,563  $6,073  $228,517 
President and Chief Executive Officer  2008  $134,250  $6,346  $4,053  $6,176  $150,825 
 
Joseph Young  2009  $110,169  $5,000  $  $  $115,169 
Principal Accounting Officer                        
(1)The amount shown for each executive officer is the amount accrued for in prior periods and paid in fiscal 2009.
(2)The amount shown for each executive officer is the amount accrued for fiscal 2009 and paid for fiscal 2008 through the Oil and Gas Incentive Compensation Plan.
(3)For Mr. Singleton, amount includes matching funds contributed by the Company to its 401(k) plan of $5,826 and $5,204 for fiscal 2009 and 2008, respectively. It also includes $247 and $850 for premiums paid by the Company on a life insurance policy for Mr. Singleton during fiscal 2009 and 2008, respectively. Mr. Singleton designates the beneficiary.
Effective April 1, 1980 the Company adopted an Oil and Gas Incentive Compensation Plan (the O&G Plan) for key employees. Through this O&G Plan, Basic pays to the O&G Plan participants, consisting of both former and current key employees, a portion of its net revenue (after deducting operating expenses) from certain properties. Under the O&G Plan rules, the portion of the net revenue contributed from any property cannot exceed 5% of the Company’s interest in that property. While payments are still made to the O&G Plan participants due to previous grants, the last time a new property was added to the O&G Plan was in 1988.
The participants in the O&G Plan made no cash outlay at the time of grantproxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in order to participate; it was entirely non-contributory, and an interest is not assignable, transferable, nor can it be pledged by the participant. Interest in the O&G Plan vested over a period ranging from four to eleven years. We can sell or otherwise transfer its interest in properties designated for the O&G Plan. If we sell a property in the O&G Plan, the participants shall receive their respective percentages of the sales price. There are currently five participants in the O&G Plan including Mr. Singleton. The other four participants are former officers who have vested interests in the O&G Plan ranging from 60 percent to 100 percent. Compensation paid or accrued through this plan to Mr. Singleton is included in the Other Annual Compensation column in the Executive Officer Compensation table above.

46


On July 27, 1995 the Board of Directors adopted the 1995 Incentive Stock Option Plan (the ISO Plan) and in October 1995, our shareholders approved the ISO Plan. The ISO Plan remained in effect for a period of ten years, expiring on July 26, 2005. This ISO Plan was established to provide a flexible and comprehensive stock option and incentive plan which permitted the granting of long-term incentive awards to employees, including officers and directors employed by us or our subsidiary, as a means of enhancing and strengthening our ability to attract and retain those individuals on whom the continued success of the Company most depends.report.
Of the 1,000,000 shares authorized under the ISO Plan, prior to its expiration, options for only 665,000 shares were granted. Of that amount and as of March 31, 2009, 50,000 options expired unexercised, and 615,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share.
In October 1997 we implemented a savings plan that allows participants to make contributions by salary reduction pursuant to Section 401(k) of the Internal Revenue Code. Employees are required to work for the Company one year before they become eligible to participate in the 401(k) Plan. The Company matches 100% of the employee’s contribution up to 3% of the employee’s salary. Contributions are vested when made. Contributions to the 401(k) Plan on behalf of Mr. Singleton are also included in the All Other Compensation column in the Summary Compensation Table above.
Outstanding Equity Awards at Fiscal Year End
As of March 31, 2009, there were no outstanding equity option awards held by either executive officer or by any of the directors.
We have no contract with any officer which would give rise to any cash or non-cash compensation resulting from the resignation, retirement or any other termination of such officer’s employment with the Company or from a change in control of the Company or a change in any officer’s responsibilities following a change in control.
Director Compensation
Prior to fiscal 2008, directors received no cash compensation for their services to the Company as directors, but were reimbursed for out-of-pocket expenses incurred to attend board meetings. However, from July 1995 until its expiration in July 2005, the Incentive Stock Option Plan (“the ISO Plan”), noted above, provided eligible, non-employee members of the Board of Directors of Basic or its subsidiaries (Non-Employee Directors), grants of certain options to purchase common stock of the Company, as compensation for their services. During the years the ISO Plan was active, 425,000 non-qualified options were granted to independent directors: 175,000 to David Flake, our former CFO, who was then an outside director of the Company. As of March 31, 2009, there were no unexercised stock options.
On March 8, 2007, the Board of Directors adopted a new Director Compensation Plan. On April 12, 2007 the Board of Directors resolved issues concerning the Plan and then ratified the Plan effective April 1, 2007.
With respect to this Plan, independent director compensation consists of a cash retainer, meeting fees, committee fees and stock grants. Independent directors receive an annual cash retainer of $16,000, in addition to $2,000 and $500 for quarterly board meetings and committee meetings (which take place as needed), respectively. Committee chairpersons of the Audit, Compensation, and Nominating Committees receive $5,500, $4,500 and $3,500, respectively. Additionally, independent board members receive an annual stock grant equal to $36,000 vested over three years. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date. Thus, effective April 1, 2008 and April 1, 2009, subject to vesting, Messrs. Robertson and Rodgers are entitled to stock grants of 36,036 and 44,888 shares each, respectively.

47


                 
  Fees Earned or      All Other    
  Paid in Cash  Stock Awards  Compensation  Total 
Name ($)  ($)  ($)  ($) 
      (1)         
Richard Rodgers $33,000  $36,000  $  $69,000 
Monroe Robertson  34,000   36,000      70,000 
             
Total  67,000   72,000      139,000 
             
(1)The amount shown for each director is the amount awarded each year vesting over a three year period.
ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Set forth below, as of June 18, 2009,
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ meeting and is information concerning stock ownership of all persons, or group of persons, knownincorporated by the Company to own beneficially 5% or more of the shares of Basic’s common stock and all directors and executive officers of the Company, both individually and as a group, who held such positionsreference in fiscal 2009. Basic has no knowledge of any other persons, or group of persons, owning beneficially more than 5% of the outstanding common stock of the Company as of March 31, 2009.this report.
             
      Shares of  Percent of 
      Common  Outstanding 
      Stock  Shares 
      Beneficially  Beneficially 
Name and Address of Beneficial Owner Type and Class  Owned  Owned 
             
Ray Singleton, Denver CO (a) Common Stock  4,505,912   25.7%
             
Richard Rodgers, Denver, CO (c) Common Stock  7,571    (d)
             
Monroe W. Robertson, Denver, CO (d) Common Stock  13,471    (d)
           
             
All officers and directors as a group (3 persons) (a), (b), and (c) Common Stock  4,526,954   25.7%
(a)All 4,505,912 shares are owned directly by Mr. Singleton.
(b)All 7,571 shares are fully vested and owned directly by Mr. Rodgers
(c)All 13,471 shares are fully vested and owned directly by Mr. Robertson.
(d)Less than 1%
Company management knows of no arrangements that may result in a change in control of Basic.

48




CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
It is Company policy that officersAND DIRECTOR INDEPENDENCE

Information relating to this item will be included in an amendment to this report or directors may assign to or receive assignments from Basic in oil and gas prospects only on the same terms and conditions as accepted by independent third parties. It is also the policy of Basic that officers or directors and Basic may participate together in oil and gas prospects generated by independent third parties only on the same terms and conditions as accepted by each other.
With respect to prospects initiated during either fiscal 2009 or 2008, none of Basic’s officers or directors participated with the Company. However, in previous years, Mr. Singleton participated with the Company in certain acquisitions. With respect to his working interest in the four wellsproxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in which he currently has a working interest, at March 31, 2009 Mr. Singleton had a balance owed to the Company of less than $1,000 compared to a balance due to him of approximately $2,000 at March 31, 2008. This was due to his share of operating expenses exceeding the amount due to him for his share of oil and gas revenue from these wells.this report.


PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table discloses
Information relating to this item will be included in an amendment to this report or in the fees that the Company was billed (and anticipates being billed)proxy statement for professional services renderedour 2010 annual stockholders’ meeting and is incorporated by its independent public accounting firmreference in eachthis report.
         
  Years Ended 
  March 31, 
  2009  2008 
Audit fees (1) $92,000  $70,000 
Audit-related fees(2)
  4,000    
Tax fees(3)
     11,500 
All other fees(4)
      
       
 
Total $96,000  $81,500 
       

Part IV
EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 
(1)Reflects fees billed for the auditDocuments filed as part of the Company’s consolidated financial statements included in its Form 10-K and review of its quarterly reportsthis Annual Report on Form 10-Q.10-K.
(2)Reflects fees, if any, for services related to financial accounting and reporting matters.
(3)Reflects fees billed for tax compliance, tax advice and preparation of the Company’s federal tax return.
(4)Reflects fees, if any, for other products or professional services not related to the audit of the Company’s consolidated financial statements and review of its quarterly reports, or for tax services.
Pre-Approval Policies and Procedures
The Audit Committee approves all audit, audit-related services, tax services and other services provided. Any services provided that are not specifically included within the scope of the audit must be pre-approved by the Audit Committee in advance of any engagement. Under the Sarbanes-Oxley Act of 2002, audit committees are permitted to approve certain fees for audit-related services, tax services and other services pursuant to a de minimus exception prior to the completion of an audit engagement. In fiscal 2009, none of the fees paid to Ehrhardt Keefe Steiner & Hottman PC were approved pursuant to the de minimus exception.

49


Part IV
ITEM 15
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Exhibits
     
Exhibit(1)Financial Statements
All financial statements as set forth under Item 8 of this report.
  
(2)Supplementary Financial Statement Schedules
None.
(3)Exhibits
See (b) below
(b)Exhibits
The following exhibits are filed pursuant to Item 601 of Regulation S-K:
Exhibit No. Document
3i13(i)a Restated Certificate of Incorporation includedof Earthstone Energy, Inc., effective May 12, 1981, as amended by (i) Certificate of Amendment of Certificate of Incorporation, effective November 20, 1986; (ii) Certificate of Amendment of Certificate of Incorporation, effective July 1, 1996; and (iii) Certificate of Designations of Series A Junior Participating Preferred Stock, effective February 5, 2009, incorporated by reference to Exhibit 3(i) of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the SEC on February 17, 2009.
3(i)bAmended and Restated Certificate of Incorporation as approved by stockholders of the Company at the Company’s 2009 Annual Meeting of Stockholders and the amendments to the Company’s Certificate of Incorporation previously disclosed in Basic’sthe Company’s proxy statement on Schedule 14A filed with the Securities and Exchange Commission on November 5, 2009, incorporated by reference to Exhibit 3(i) on Form 8-K filed with the SEC on March 3, 2010.
3(ii)aBylaws of Earthstone Energy, Inc., dated July 15, 1986, as amended by First Amendment to Bylaws, dated February 4, 2009, incorporated by reference to Exhibit 3(ii) of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the SEC on February 17, 2009.
3(ii)bAmended and Restated Bylaws reflecting recent changes made to the Company’s Certificate of Incorporation to remove certain outdated and redundant provisions that existed in our prior bylaws with respect to corporate governance, stockholder and director meeting procedures, and indemnification procedures.  Changes to the bylaws include, among other things: (i) amendments to reflect the new name of the Company; (ii) expansion of certain provisions with respect to stockholders’ meetings and record dates; (iii) amendments in respect of corporate governance, board committees, and board meetings; (iv) amendments to certain provisions in respect of officers and their duties; (v) amendments to certain provisions in respect of share certificates; and (vi) removal of indemnification provisions are incorporated by reference to Exhibit 3(ii) on Form 8-K filed with the SEC on March 3, 2010.
4.1Rights Agreement, dated February 4, 2009, between Earthstone Energy, Inc. and Corporate Stock Transfer, Inc., incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K., filed with the SEC on February 5, 2009.
10.1*Oil and Gas Incentive Compensation Plan, dated April 1, 1980, as amended, incorporated by reference to our Annual Report on Form 10-K for the fiscal year ended March 31, 19811985, filed with the SEC.
3i1(b) By-laws included in Basic’s Form S-1 filed October 24, 1980Exhibits (continued)
3i1Exhibit No. Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996Document
10(i)a110.2 Loan Agreement, dated March 4, 2002, between The Bank of Cherry Creek and Basic, datedEarthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 4,31, 2002,
10(i)a1 filed with the SEC on June 28, 2002; as amended by Amended Loan Agreement, dated January 3, 2006, between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.
Earthstone, incorporated by reference to Exhibit 10(i)a1 of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2006, filed with the SEC on July 14, 2006; and as further amended by Amended Loan Agreement, dated December 31, 2006, between American National Bank (formerly The Bankand Earthstone, incorporated by reference to Exhibit 10(i)a of Cherry Creek) and Basic dated December 31, 2006
10(ii)1Oil and Gas Incentive Compensation Plan included in Basic’sour Annual Report on Form 10-K10-KSB for the fiscal year ended March 31, 19852009, filed with the SEC on June 29, 2007.
10(ii)110.3* Performance Bonus Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.3 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
10.4*Director Compensation Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.4 of our Amended 10-K/A, filed with the SEC on October 9, 2009 as amended by board resolution dated March 31, 2010, filed herewith.
10.5*Form of Restricted Stock Agreement dated effective aspursuant to the Director Compensation Plan, incorporated by reference to Exhibit 10(ii) of April 7, 2007
211Subsidiaries of Basic included in Basic’sthe Annual Report on Form 10-KSB for the fiscal year ended March 31, 20022008, filed with the SEC on July 11, 2008.
31.110.6* Part-Time Employment and Confidentiality Agreement, effective March 31,2008, between Joseph Young and Earthstone, incorporated by reference to Exhibit 10.6 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
14.1Code of Business Conduct and Ethics, incorporated by reference to Exhibit 14.1 of our Annual Report on Form 10-KSB/A for the fiscal year ended March 31, 2004, filed with the SEC on May 11, 2005.
16.1Letter Regarding Change in Certifying Accountant, incorporated herein by reference to Exhibit 16.1 of our Current Report on Form 8-K, filed with the SEC on July 21, 2008.
21List of Subsidiaries of Earthstone, incorporated by reference to Exhibit 21 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer)
 Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
 Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).
99.1
 Nominating Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.1 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
199.2 PreviouslyCompensation Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.2 of our Amended 10-K/A, filed and incorporated herein by referencewith the SEC on October 9, 2009.
Report of Ryder Scott Company filed herewith.
Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.

50

*Indicates management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15 of Form 10-K.




In accordance with the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this reportamendment to be signed on its behalf by the undersigned, thereunto duly authorized.authorized by the following in the capacities and on the dates indicated.
BASIC EARTH SCIENCE SYSTEMS,
EARTHSTONE ENERGY, INC.

   
  Date
  Date
By: /s/ Ray Singleton
June 18, 2010
Ray Singleton, President    
  
   
By: /s/ Joseph Young
 June 18, 2010
   
By:/s/ Ray SingletonJune 18, 2009
Ray Singleton, President
By:/s/ Joseph YoungJune 18, 2009
Joseph Young,
  
Principal Accounting Officer  

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

   
Name and Capacity Date
  
By: /s/ Ray Singleton
June 18, 2010
   
Ray Singleton, Director  
   
By: /s/ Richard K. Rodgers
 June 18, 2010
   
By:/s/ Ray SingletonJune 18, 2009Richard K. Rodgers, Director and  
Ray Singleton, Director
Compensation Committee Chairman  
   
By: /s/ Monroe W. Robertson
 June 18, 2010
   
By:/s/ Richard K. RodgersJune 18, 2009
Richard K. Rodgers, Director and
Compensation Committee Chairman
By:/s/ Monroe W. RobertsonJune 18, 2009
Monroe W. Robertson, Director and
  
Audit Committee Chairman  

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EXHIBIT INDEX
Exhibits
Exhibit
No.Document
3i1Restated Certificate of Incorporation included in Basic’s Form 10-K for the year ended March 31, 1981
3i1By-laws included in Basic’s Form S-1 filed October 24, 1980
3i1Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996
10(i)a1Loan Agreement between The Bank of Cherry Creek and Basic, dated March 4, 2002
10(i)a1Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006.
10(i)a1Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated December 31, 2006
10(ii)1Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985
10(ii)1Restricted Stock Agreement dated effective as of April 7, 2007
211Subsidiaries of Basic included in Basic’s Form 10-KSB for the year ended March 31, 2002
31.1Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
31.2Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer)
32.1Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
32.2Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).
1Previously filed and incorporated herein by reference
Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.

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