EARTHSTONE ENERGY INC - FORM 10-K

Attached files

file	filename
EX-4.2 - SPECIMAN STOCK CERTIFICATE - EARTHSTONE ENERGY INC	earthstoneexh42.htm
EX-10.7 - FINANCIAL CONSULTING AGREEMENT - EARTHSTONE ENERGY INC	earthstoneexh107.htm
EX-99.3 - REPORT - EARTHSTONE ENERGY INC	earthstoneexh993.htm
EX-32.2 - CERTIFICATION - EARTHSTONE ENERGY INC	earthstone3312011exh322.htm
EX-31.2 - CERTIFICATION - EARTHSTONE ENERGY INC	earthseono3312011exh312.htm
EX-32.1 - CERTIFICATION - EARTHSTONE ENERGY INC	earthstone3312011exh321.htm
EX-31.1 - CERTIFICATION - EARTHSTONE ENERGY INC	earthstone3312011exh311.htm

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, 2011


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

Commission file number: 0-7914

(Exact Name of Registrant as Specified in its Charter)

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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, $0.001 par value per share		The NASDAQ Stock Market LLC

Securities registered under Section 12(g) of the Act: NONE

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No þ

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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 post such filed). Yes o No o

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

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer o (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). Yes o No þ

Registrant’s revenues for its most recent fiscal year: $8,206,000

The aggregate market value of registrant’s common stock held by non-affiliates was approximately $14,637,376 as of the registrant’s most recently completed second fiscal quarter.

As of June 10, 2011, 1,712,744 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from portions of the registrant's definitive Proxy Statement for its 2011 Annual Meeting of Shareholders to be filed, pursuant to Regulation 14A, no later than 120 days after March 31, 2011.

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. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "predict," "plan," "should", "likely", "may", "will", "continue" or similar expressions are intended to identify such statements. All statements other than statements of historical facts that address activities that we intend, expect or anticipate will or may occur in the future are forward-looking statements. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty. Forward-looking statements relate to, among other things:

•	our stragegies, either existing or anticipated;
•	our future financial position, including anticipated liquidity;
•	our ability to satisfy obligations from cash generated from operations;
•	amounts and nature of future capital expenditures;
•	acquisitions and other business opportunities;
•	operating costs and other expenses;
•	wells expected to be drilled, other anticipated exploration efforts and the expenses associated therewith;
•	our asset retirement obligation;
•	estimates of proved oil and natural gas reserves, deferred tax assets, and depletion rates;
•	our ability to meet additional acreage, seismic and/or drilling cost requirements arising from acquisition opportunities;
•	other estimates and assumptions we use in our accounting policies; and
•	future share repurchases.

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;
•	mechanical failure;
•	the actual costs related to asset retirement obligation, and whether or not those retirements actually occur in the future;
•	the potential unavailability of drilling rigs and other field equipment and services;
•	the existence of unanticipated liabilities or problems relating to acquired properties;
•	factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment;
•	the willingness and ability of third parties to honor their contractual commitments;
•	permitting issues;
•	the nature, extent and duration of workovers;
•	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;
•	general economic, market or business conditions;
•	weather;
•	any change in interest rates or inflation;
•	a lack of available capital and financing;

•	risk factors consistent with comparable companies within our industry, especially companies with similar market capitalization and/or employee census; and
•	other factors, many of which are beyond our control.

Furthermore, forward-looking statements are made based on our current assessment available at the 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 any 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. As with comparable companies within our industry, there are numerous factors that could cause actual results to differ materially from our expectations. All forward-looking statements speak only as of the date made. 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.

GLOSSARY OF TERMS

Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report:

Terms used to describe quantities of crude oil and natural gas:

“Bbl” – Barrel or 42 U.S. gallons liquid volume.

“BOE” – Barrels of crude oil equivalent.

“Condensate” – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“Mcf” – Thousand cubic feet of gas.

Terms used to describe our interests in wells and acreage:

“Gross acres” – The number of acres in which we own a gross working interest.

“Gross well” – A well in which we own a working interest.

“Net acres” – Our percentage ownership of gross acreage. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

“Net well” – Deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

“Developed acreage” – Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

“Development well” – A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves.

“Dry hole” – An exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.

“Exploratory well” – A well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.

“Productive well” – An exploratory or a development well that is not a dry hole.

“Undeveloped acreage” – Leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage includes net acres under the bit until a productive well is established in the spacing unit.

“Unproved property” – A property or part of a property with no proved reserves.

“Unsuccessful efforts” – Drilling activities that result in a dry hole. Costs associated with unsuccessful efforts are part of the cost to discover reserves, therefore are capitalized in the full cost pool.

Terms used to describe seismic activity and operations:

“3-D Bright Spot” – A geophysical amplitude anomaly which is simply a velocity change from high to low. Sands that contain gas are predicted by this method because the gas provides a slower velocity response giving an abnormally intense trough-peak reflection, therefore termed a Bright Spot.

“Formation fracturing” – The injection of water, sand and additives under extremely high hydraulic pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.

“Horizontal Drilling” – A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontal within a designated zone typically defined as the prospective pay zone to be completed for oil and/or gas.

“Hydraulic stimulation technology” – A process that results in the creation of fractures in rocks. The fracturing is done from a wellbore drilled into reservoir rock formations to increase the rate and ultimate recovery of oil and natural gas.

“Plugging and abandonment” – The sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

“Proppant” – A material, such as grains of sand, ceramic, or other particulates, that prevent the fractures from closing when the injection is stopped.

“Recompletion” – The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Workover” – Operations on a producing well to restore or increase production.

Terms used to describe the legal ownership of our oil and natural gas properties:

“Revenue interest” – The amount of interest owned in the proceeds derived from a producing well less all royalty interests.

“Working interest” – The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Terms used to assign a present value to or to classify our reserves:

“Possible reserves” – Reserves for which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

“PV-10” – The estimated future cash flow, discounted at a rate of 10% per annum, with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

“Probable reserves” – Reserves for which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.

“Proved developed non-producing reserves” – Proved crude oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

“Proved developed reserves” – Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“Proved reserves” – Proved crude oil and natural gas reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves” – Proved crude oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir.

“Standardized Measure” – The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

Other Terms:

“Farmout” – An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farmin" while the interest transferred by the assignor is a "farmout."

“Field” – An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

“Play” – An accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area expanse.

“Prospect” – A location where hydrocarbons such as oil and gas are believed to be present in quantities which are economically feasible to produce.

“Reservoir” – A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Resources” – Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Earthstone Energy, Inc.

Form 10-K

March 31, 2011

Table of Contents

	Part I	Page
Item 1	Description of Business	10
Item 1A	Risk Factors	15
Item 1B	Unresolved Staff Comments	15
Item 2	Description of Property	15
Item 3	Legal Proceedings	20

	Part II
Item 5	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	21
Item 6	Selected Financial Data	23
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8	Financial Statements and Supplementary Data	31
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	52
Item 9A	Controls and Procedures	52
Item 9B	Other Information	53

	Part III
Item 10	Directors, Executive Officers and Corporate Governance	54
Item 11	Executive Compensation	54
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	54
Item 13	Certain Relationships and Related Transactions and Director Independence	54
Item 14	Principal Accountant Fees and Services	54

	Part IV
Item 15	Exhibits, Financial Statement Schedules	55
	Signatures	57

Part I

ITEM 1

DESCRIPTION OF BUSINESS

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. (“Earthstone” or “the Company” or “we” or “our” or “us”) is a growth-oriented independent oil and gas exploration and production company primarily engaged in the exploration, development and production of oil and natural gas properties. We have an established production base that generates positive cash flow from operating activities and profits. Our operating activities are concentrated in the North Dakota and Montana portions of the Williston basin, the southern portions of Texas, onshore portions of the Gulf Coast, and the Denver-Julesburg basin of Colorado. As of March 31, 2011, our estimated net proved oil and natural gas reserves were 1,015,000 Bbls of oil and condensate and 735,000 Mcfs of natural gas.

Strategy

Our primary objective is to enhance shareholder wealth by increasing our net asset value, net reserves and cash flow through acquisitions, exploration, development, exploitation, and divestiture of oil and gas properties following a balanced risk strategy.

The four key 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.

	•		Utilization of strategic partners with industry experience in the specific geographic areas for which we desire to expand.
	•		Cost effective implementation of internally and externally generated exploration and development drilling projects.

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

Our primary operational focus is in the Montana and North Dakota portions of the Williston basin. 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. Accordingly, we have a significant understanding of, and exposure to, both the local geology and geologic processes.

The Williston basin and our south Texas waterfloods are primarily oil producing properties. In an effort to expand our reserves and to diversify our portfolio of properties, we have undertaken efforts in other areas, notably, Colorado, Nebraska and onshore portions of the Gulf Coast. Last year, drilling, particularly non-operated drilling projects, comprised the majority of capital expenditures. In the coming year we expect this trend to continue despite our continued emphasis on the acquisition of producing properties. While we expect to drill a considerable number of wells for our size, this effort is primarily to protect expiring leases and maintain our interests under existing acreage holdings. Historically, we have not placed emphasis on acquiring new, large, non-producing acreage positions. In the coming year, as our existing inventory of acreage is developed, we could see the need to shift capital expenditure dollars into undeveloped acreage.

We will be focusing on keeping our operating costs under control, as we expect rig and vendor service costs to continue to escalate due to high demand. Maintaining a low overhead structure is fundamental to our cost containment. However, over the last year we have expanded and/or restructured our staff; primarily to comply with increased SEC regulation. Since our fiscal year end, we have added additional operational staff, and expect to continue to do so, as we increase our capacity to drill more wells. We are using and will continue to use the services of independent consultants and contractors to perform various professional services. We believe that this use of third-party service providers enhances our ability to contain general and administrative expenses.

We caution that the following expectations may be altered by subsequent events or other, more attractive opportunities that may present themselves in the future.

On-Going Activities

Williston Basin. The Williston basin continues to be our highest area of activity, both in terms of cash flow from existing properties and expenditures for drilling efforts as well as the acquisition of producing properties. We have several areas within the Williston basin where we expect drilling operations to commence and/or continue in 2011. These areas are the Banks Field in McKenzie County, North Dakota, the Mondak Field in McKenzie County, North Dakota, the Elm Coulee Field in Richland County, Montana, our acreage in the Indian Hill Field in McKenzie County and our acreage in Divide County, North Dakota and Sheridan County, Montana. While not our primary area of focus, we continue to deploy capital in legacy areas beyond the Williston basin to exploit reserve potential on existing properties.

Banks Field — McKenzie County, North Dakota. Earthstone retains a 6.5% working interest in approximately 13,000 gross (845 net) acres in and around the Banks field. Early efforts on this prospect were less than successful. With improvements in hydraulic stimulation technology, this area is now much more attractive. In the last year, two companies, Zenergy and SM Energy, have drilled five wells on the prospect. Two wells are now on production (the Pederson 10-3H and Fossom 15-35H). At March 31, 2011, three wells (Ceynar 29-32H, A. Johnson 12-1H and Berquist 33-28H) had been drilled, but not yet completed. In addition, we anticipate Brigham to drill ten wells on this acreage before calendar year end and we have already executed AFEs authorizing the drilling of six of the possibly ten wells.

Mondak Field — McKenzie County, North Dakota. The Company has an interest in three wells in the Mondak Field. One of these wells was drilled in the year ended March 31, 2011. This well, the Mondak Federal 24X-12, is still being completed and not yet on production. This acreage is currently developed for one well per spacing unit. However, we anticipate that this acreage will be developed for two wells per spacing unit in the future.

Elm Coulee Field — Richland County, Montana. The Company has an interest in four horizontal Bakken wells in the Elm Coulee Field and several, legacy, vertical wells that hold Bakken acreage. Most areas in the Elm Coulee Field contain two wells per spacing unit. Now that this field is reaching maturity, it is not unreasonable to expect select areas of this field to be developed with three wells per spacing unit. We believe it is likely that this will occur in the coming year.

Indian Hill Field — McKenzie County, North Dakota. The Company holds approximately 960 gross (192 net) acres in the Indian Hill Field. With improving hydraulic stimulation technology, a number of Bakken horizontal wells have been drilled in the area. We anticipate that this acreage will be proposed for horizontal Bakken development in the coming year.

Divide County, North Dakota — Sheridan County, Montana. Recently, several companies have drilled in these two counties in the Bakken Shale, resulting in strong production figures. Also in the third and fourth quarter of this year, we acquired a 26.5% working interest in five producing wells and a 25% interest in a shut-in well in Sheridan County, Montana. By virtue of these acquisitions, in addition to the legacy producing properties in these two counties, along with undeveloped leasehold acreage, the Company has an estimated 15,200 gross (4,000 net) acres which could be evaluated for horizontal Bakken development in the coming years.

Other Areas

Denver-Julesburg Basin — Weld County, Colorado. As of March 31, 2010, we had finished the first and second phase of our project to (1) drill and complete sixteen new down-spaced wells on the Antenna Federal property in Weld County, Colorado and (2) to drill six “edge wells” around this property. All development work on the phase one and two on this 640 acre section has been finalized. During the year ended March 31, 2011, we recompleted nine of the existing Codell wells into the J-Sand formation. Kerr-McGee Oil & Gas Onshore, LP is the operator of this project.

Reserves

During the year ended March 31, 2011, our proved reserves in BOE and PV-10 increased approximately 17% and 42%, respectively (from March 31, 2010). Additional information about our reserves and the calculation of reserves may be referenced in Item 2. “Properties.”

Contemplated Activities

We are continually evaluating other drilling and acquisition opportunities for possible participation. 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 evaluation 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 divestitures, 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, and development for and of crude oil and natural gas. While we operate a small number of oil wells, 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. All of our operations are conducted in the United States. Consequently, we presently report under a single industry segment.

Markets. We are a small company and, as such, have no impact on the market for our product and little control over the price received. Markets for crude oil and natural gas are volatile 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 our natural 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 from areas unaffected by supply disruptions. 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. During the year ended March 31, 2011, approximately 48% of our oil and natural gas production revenues were received from sales to nine purchasers (compared to 43% to six purchasers in the previous fiscal year). The remaining 52% of our revenue was received from non-operated properties where we have no direct contact with the purchaser. On these properties our portion of the product is marketed on our behalf by the 23 different companies who operate these wells. These 23 companies may, unbeknownst to us, market to one or more of the same purchasers to whom we sell directly. 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 these purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%. It is not expected that the loss of any one of these purchasers would cause a material adverse impact on the Company’s results from operations, as alternative markets for oil and natural gas production are readily available. Should we require a new buyer of our production, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

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 having such resources to accelerate our efforts. Competition is intense with respect to acquisitions and the purchase of large producing properties. Due to the limited capital resources available to us, we have historically focused on smaller and/or marginal properties with behind-pipe potential in our acquisition efforts. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.

Employees

As of March 31, 2011, we had eight full-time, two part-time employees and two part-time contractors. Four of these employees are primarily field laborers and are located at our subsidiary’s (Basic Petroleum Services, Inc.) field office in Bruni, Texas, forty-five miles southeast of Laredo, Texas. In addition, in other areas, we have seven contract field workers on a part-time retainer basis. We believe our employee and contractor relations are good.

Regulations

General. Our company is 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, the subsequent rehabilitation of the well site 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 have expended, and expect to expend in the future, significant funds to comply with such laws and regulations. Changes to current local, state or federal laws and regulations in the jurisdictions 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 projects.

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.

Available Information

We make available on our website, earthstoneenergy.com, under “Investor Relations, SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”).

Our Code of Business Conduct and Ethics, Board of Directors Committee Charters (Audit, Nominating, and Compensation Committees), and Whistleblower Policy are also available on our website under “Investor Relations, Corporate Governance.”

ITEM 1A

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 reporting under this 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 other comparable companies within our industry, especially companies with similar market capitalization and/or employee census.

ITEM 1B

UNRESOLVED STAFF COMMENTS

None.

ITEM 2

DESCRIPTION OF PROPERTY

Producing Properties: Location and Impact

As of March 31, 2011, we owned a working interest in 83 gross producing oil wells and 44 gross producing gas wells in six states: North Dakota, Montana, Colorado, Texas, Louisiana and Wyoming.

Productive Wells

	Gross Wells				Net Wells
	Oil		Gas		Oil		Gas

Colorado		—		41		—		13.66
Louisiana		2		—		0.11		—
Montana		21		—		9.12		—
North Dakota		31		2		7.80		0.12
Texas		28		1		24.36		0.13
Wyoming		1		—		0.47		—

Total		83		44		41.86		13.91

Production

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

Reserves

As of March 31, 2011, our estimated proved developed and undeveloped oil and natural gas reserves in barrels of oil equivalent (“BOE”) was 1,137,000, a 17% increase from the prior year end’s estimated proved oil and natural gas reserves of 970,000 BOE. This increase primarily reflects the addition of new wells, along with an increase in the life of existing wells due to an increase in oil and natural gas prices.

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 onshore south Texas. The following table summarizes the estimated proved developed and undeveloped oil and natural gas reserves divided between operated and non-operated properties for these three areas as of March 31, 2011:

Estimated Proved Oil and Gas Reserves by Area

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

Williston Basin
Operated		176,763		75,763		189,390		16.7	%
Non-Operated		397,698		221,519		434,618		38.2	%
		574,461		297,282		624,008		54.9	%


South Texas/Onshore Gulf Coast
Operated		388,103		—		388,103		34.1	%
Non-Operated		—		—		—		—	%
		388,103		—		388,103		34.1	%


D-J Basin
Operated		16,109		172,353		44,835		4.0	%
Non-Operated		35,891		265,358		80,117		7.0	%
		52,000		437,711		124,952		11.0	%


Total		1,014,564		734,993		1,137,063		100.0	%

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 natural gas reserves have been estimated as of March 31, 2011, 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 91% and 93% of the PV-10 of our oil and gas reserves as of March 31, 2011 and 2010, 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. The office of Ryder Scott that prepared our reserve estimate is registered in the state of Texas (License #F-1580). Ryder Scott prepared our reserves estimates based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for our wells. Additionally, authorizations for expenditure ("AFEs"), geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to such engineer for consideration in estimating our underground accumulations of crude oil and natural gas. This information was reviewed by Ray Singleton, our President and Chief Executive Officer, to ensure accuracy and completeness of the data prior to and after submission to Ryder Scott. 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. The report of Ryder Scott dated May 6, 2011, 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 24 of our 127 producing properties because of their relatively low values. Instead, reserves for these properties were prepared by in-house personnel and contributed 9% and 7% to our reserves as of March 31, 2011 and 2010, respectively. Internal reserve estimates were prepared by Ray Singleton, President and Chief Executive Officer, whose qualifications are summarized above.

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.

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 reserves 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, 2011. All of our reserves are located in the United States.

Estimated Proved Developed and Undeveloped Oil and Gas Reserves

Proved Developed

Producing

Non-Producing

Proved Undeveloped

Total Proved

Net Remaining Reserves

Oil/Condensate – Bbls

1,015,000

―

1,015,000

Plant Products – Bbls

―

Gas – Mcf

735,000

―

735,000

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 on Form 10-K. In addition, estimates of proved reserves are subject to revision to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based.

Additional information pertaining to our proved reserves is set forth under the heading "Unaudited Oil and Gas Reserves Information" in the notes to the consolidated financial statements included later in this Annual Report on Form 10-K.

Proved Undeveloped Reserves

As of March 31, 2011, we had no proved undeveloped reserves.

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 years ended March 31, 2011 and 2010.

Drilling Activities

The following table sets forth our gross and net working interests in exploratory and development wells drilled during the years ended March 31, 2011, 2010, and 2009, respectively:

Exploratory and Developmental Wells Drilled

2011

2010

2009

Gross

Net

Gross

Net

Gross

Net

Exploratory

Productive

Oil

―

0.01

Gas

―

Dry holes

―

0.55

―

Total

―

0.55

0.01

Development

Productive

Oil

5.11

0.36

0.09

Gas

0.17

―

2.27

Dry holes

―

Total

5.28

0.36

2.36

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 follows:

Gross and Net Acreage

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net

Colorado		640		384		—		—
Louisiana		687		51		—		—
Montana		7,051		3,131		11,876		3,078
Nebraska		—		—		84,944		18,470
North Dakota		7,096		2,714		19,900		3,717
Texas		3,080		2,486		—		—
Wyoming		1,555		329		40		1

Total		20,109		9,095		116,760		25,266

Field Service Equipment

As of March 31, 2011, our 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 $6,000 per month plus maintenance fees 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 6 to the consolidated financial statements.

ITEM 3

LEGAL PROCEEDINGS

None.

Part II

ITEM 5

MARKET FOR REGISTRANT’S COMMON EQUITY,

RELATED SHAREHOLDER MATTERS

AND ISSUER PURCHASES OF EQUITY SECURITIES

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

Effective December 31, 2010, the Board of Directors authorized and effected a 1-for-10 reverse stock split which converted ten (10) shares of the Company’s common stock into one (1) share of common stock. All following references to the number of common shares, treasury shares, and per share amounts reflect the reverse stock split.

Our common stock is currently quoted on the NASDAQ Global Select Market under the ticker symbol “ESTE.” Prior to January 26, 2011, our stock was traded on the Over-the-Counter Bulletin Board (“OTCBB”) under the symbol “BSIC.”

The closing bid price on NASDAQ of our common stock on June 10, 2011, was $14.14. The following table sets forth the quarterly high and low sales prices of our common stock as reported on NASDAQ for the period from January 26, 2011 through March 31, 2011:

	High			Low
Fourth Quarter¹	$	25.25		$	13.56

Our common stock commenced trading on NASDAQ on January 26, 2011.

The following table sets forth the range of high and low bid quotations of our common stock for each of the periods indicated below as reported by the OTCBB. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

	Year Ended March 31,
	2011				2010
	High		Low		High		Low

First Quarter	$	14.40	$	6.00	$	9.90	$	6.50
Second Quarter		13.00		9.20		9.50		7.30
Third Quarter		24.00		9.00		8.90		6.82
Fourth Quarter¹		19.40		13.50		9.30		7.00

Our common stock commenced trading on NASDAQ on January 26, 2011.

As of June 10, 2011, we had approximately 1,964 shareholders of record. We have never paid a cash dividend on our common stock. Any future dividend on common stock will be at the discretion of the Board of Directors and will be dependent upon the Company’s earnings 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.

Unregistered Sales of Equity Securities

Not applicable.

Securities Authorized For Issuance under Equity Compensation Plans

The following table contains information with respect to our Director Compensation Plan as of March 31, 2011.

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

Equity compensation plans approved by security holders	―	N/A	―

Equity compensation plans not approved by security holders	―	N/A	―

Total	―	N/A	20,716

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 shares having a fair market value equal to $36,000 on April 1 of each year as further described below. 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.

The Plan allows up to 50,728 shares of the Company’s common stock to be issued to directors under the Plan, subject to certain restrictions and vesting, of which 9,270 shares were granted during the year ended March 31, 2011, for a total of 30,012 shares that have been granted as of March 31, 2011. Accordingly, as of the year ended March 31, 2011, 20,716 shares of common stock remain available for issuance under the Plan.

Grants of shares of restricted stock vest one-third each year over three years. 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 March 31, 2011, for each non-employee director was as follows: Robertson – 8,555 shares; Rodgers – 8,555; and Calerich – 552.

In addition, on April 1, 2011, each of the three non-employee directors was granted 1,867 shares of restricted stock on April 1, 2011, subject to vesting and forfeiture, resulting in 15,115 shares of common stock remaining available for issuance under the Plan as of June 10, 2011. All restricted shares are considered issued and outstanding shares of the Company’s common stock at the grant date and have the same dividend and voting rights as other common stock.

Purchases of Equity Securities

The following summarizes monthly share repurchase activity for the fourth quarter of the year ended March 31, 2011:

	Total Number of Shares Purchased¹		Average Price Paid Per Share		Number of Shares Purchased as Part of a Publicly Announced Plan¹		Maximum Shares that May Yet be Purchased under the Plan¹

January 1, 2011 - January 31, 2011		1,020	$	15.48		1,020		109,440
February 1, 2011 - February 28, 2011		—	$	—		—		109,440
March 1, 2011 - March 31, 2011		—	$	—		—		109,440

Total		1,020				1,020

On October 22, 2008, the Company’s Board of Directors authorized a share buyback program for the Company to repurchase up to 50,000 shares of its common stock for a period of up to 18 months. The program 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 150,000. 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, 2011, 10,997 shares were repurchased under the share buyback program and 109,440 shares remain available for future repurchase.

ITEM 6

SELECTED FINANCIAL DATA

As a “smaller reporting company,” we are not required to provide this information.

ITEM 7

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

As an oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially and adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is to a large extent determined by factors beyond our control.

Liquidity and Capital Resources

Liquidity Outlook. Our primary source of funding is the net cash flow from the sale of our oil and natural 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 sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. At the current price of oil, we believe the cash generated from operations, along with existing cash balances, should enable us to meet our existing and normal recurring obligations during the next year and beyond.

Overview of our Capital Structure. 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 the enhancement of held and newly 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 natural 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.

Hedging. During the years ended March 31, 2011 and 2010, we did not participate in any hedging activities, nor did we have any open futures or option contracts. Additional information concerning our hedging activities appears in Note 1 to the consolidated financial statements.

Working Capital. As of March 31, 2011, we had a working capital surplus of $4,930,000 (a current ratio of 3.96:1) compared to a working capital surplus as of March 31, 2010 of $5,062,000 (a current ratio of 3.53:1). The increase in current ratio is primarily a result of the timing between payments made for payables, cash received for revenue and joint interest billings and the timing and use of prepaid balances in addition to the use of cash for the acquisition, development and exploration of oil and gas properties.

Cash Flow. Cash provided by operating activities decreased 2% from $2,666,000 for the year ended March 31, 2010 to $2,624,000 for the year ended March 31, 2011. This change related primarily to the timing and collection of accounts receivable, the timing and payment of accounts payable and accrued liabilities, and the application of prepaid balances.

Net cash used in investing activities more than doubled from the previous year from $1,641,000 for the year ended March 31, 2010 to $3,356,000 for the year ended March 31, 2011, which relates primarily to our drilling and completion activities during the year. The difference relates primarily to expenditures made during the year ended March 31, 2011, on an acquisition of producing properties, new horizontal Bakken wells in the Williston basin, the recompletion of D-J basin wells in Colorado and on additional acreage.

Net cash used in financing activities was nearly half of that of the pervious year. During the year ended March 31, 2010, $208,000 was used to purchase treasury shares, while $122,000 was utilized for treasury share acquisition for the year ended March 31, 2011. The Company’s share buyback program was adopted in October 2008 and will terminate in October 2011, if not extended before then.

Capital Expenditures

The amounts presented herein are presented on an accrual basis, and as such may not be consistent with the amounts presented on the consolidated statements of cash flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.

During the year ended March 31, 2011, we spent $2,729,000 on various projects. This compares to $2,156,000 for the year ended March 31, 2010. During the year ended March 31, 2011, capital expenditures were comprised of acquisitions (47%), drilling and completions (46%) and leasehold (7%). Approximately half of capital expenditures occurred in the Williston basin where funds were spent on the purchase of producing wells, new wells drilled within the Bakken development area and additional leasehold acreage. Approximately 20% of expenditures were spent on drilling and recompletion in the D-J basin. The remainder was spent in other areas on property improvements and leasehold acreage. These projects were funded entirely with internally generated cash flow.

As of March 31, 2011, we have AFEs totaling $588,000 for our share in completion costs of new wells in which we share a working interest. At present cash flow levels, we expect to have sufficient funds available for our share of both the outstanding AFEs and any additional acreage, seismic and/or drilling cost requirements that might arise from our existing opportunities. We may alter or vary all or part of any planned capital expenditures for reasons including, but not limited to changes in circumstances, unforeseen opportunities, the inability to negotiate favorable acquisition, farmout, joint venture or divestiture terms, commodity prices, lack of cash flow, and lack of additional funding.

We are continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of evaluation. 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. We caution that the absence of news and/or press releases should not be interpreted as a lack of development or activity.

Divestitures/Abandonments

We sold five wells and plugged eight wells during the year ended March 31, 2011.

Impact of Inflation and Pricing

We deal primarily in U.S. 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. However, the oil and natural gas industry can be cyclical and the demand for production places pressure on the economic stability and pricing within the industry. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, cost declines are likely to lag and may not adjust downward in proportion to declining prices. Changes in prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel. While we do not presently expect business costs to materially rise, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Other Commitments

Other than the aforementioned outstanding AFEs, we do not have any other commitments beyond our office lease and software maintenance contracts. See Note 6 to the consolidated financial statements.

Results of Operations

Selected Financial Information

The following provides selected financial information and averages for the years ended March 31, 2011 and 2010. Certain prior year amounts may have been reclassified to conform to the current presentation.

	Year Ended March 31,
	2011		2010

Revenue
Oil	$	6,933,000	$	6,223,000
Gas		1,166,000		996,000
Total revenue2		8,099,000		7,219,000

Total production expense3		3,527,000		2,942,000

Gross profit	$	4,572,000	$	4,277,000

Depletion expense	$	1,131,000	$	1,185,000


Sales volume
Oil (Bbls)		93,613		98,865
Gas (Mcf) 1		172,386		228,575

Average sales price4
Oil (per Bbl)	$	74.06	$	62.94
Gas (per Mcf)	$	6.76	$	4.36

Average per BOE
Production expense3,4	$	28.83	$	21.48
Gross profit4	$	37.37	$	31.23
Depletion expense4	$	9.24	$	8.65

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, 2011, this revenue amount is net of $107,000 in well service and water disposal revenue, which would otherwise total $8,206,000 in revenue for the year ended March 31 2011, compared to $50,000 to total $7,269,000 for the year ended March 31, 2010.
3		Overall lifting cost (oil and gas production expenses and production taxes)
4		Averages calculated based upon non-rounded figures

The Year Ended March 31, 2011 Compared with the Year Ended March 31, 2010

Overview. Net income for the year ended March 31, 2011, was $1,602,000 compared to net income of $1,028,000 for the year ended March 31, 2010, a 56% increase. The increase in sales prices, as offset by a decline in sales volumes and increase in production costs, resulted in the increase in net income. While overall production expenses increased as compared to these expenses for the year ended March 31, 2010, general and administrative expenses declined when compared to the year ended March 31, 2010.

Revenues. Oil and natural gas sales revenue increased $880,000 (12%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010, primarily due to higher realized oil and gas prices per barrel of oil equivalent (“BOE”), as offset by reduced sales volumes.

Volumes and Prices. On an equivalent barrel basis, sales decreased 11% from 137,000 BOE for the year ended March 31, 2010 to 122,000 BOE for the year ended March 31, 2011.

Oil sales volumes decreased 5% from 98,865 barrels for the year ended March 31, 2010 to 93,613 barrels for the year ended March 31, 2011, while the average price per barrel increased 18% from $62.94 for the year ended March 31, 2010 to $74.06 for the year ended March 31, 2011. The decrease in volumes was primarily related to production declines on two wells; the Halvorsen 31X-36 in the Williston basin and the USA 4-36 in the D-J basin. These two wells, both newly drilled in 2009, contributed high initial production for the year ended March 31, 2009. As anticipated, during the year ended March 31, 2011, these two wells exhibited steep, but normal initial declines; thereby reducing oil sales by approximately 4,731 barrels from the year ended March 31, 2010. To a lesser extent, for the reasons detailed in the paragraph below, oil volumes in the D-J basin reported in our Form 10-K for the year ended March 31, 2010 were not representative of normal oil sales. Oil sales from these wells were approximately 1,200 barrels higher than actual volumes sold in the period.

Natural gas sales volumes decreased 24% from 228,575 Mcf for the year ended March 31, 2010 to 172,386 Mcf for the year ended March 31, 2011, while the average price per Mcf increased 55%, from $4.36 for the year ended March 31, 2010 to $6.76 for the year ended March 31, 2011. This apparent decline in gas sales volume was attributable to the reporting for the year ended March 31, 2010 a portion of gas volumes for the year ended March 31, 2009 due to inaccurate estimates at the close of the year ended March 31, 2009. In March 2010, we received and reported in our Form 10-K for the year ended March 31, 2010, gas sales that exceeded our previous accrued estimates of gas sales from periods back to April 2008. From April 2008 to September 2009, the operator of our D-J basin wells was in the midst of an accounting system conversion and furnished us with minimal data. In those prior periods, we estimated and accrued gas sales based on the information available at the time. Had accurate information on gas sales been available and reported in those prior periods, our reported gas sales volumes in our Form 10-K for the year ended March 31, 2010, would have been lower than those reported. Excluding the volumes reported for the year ended March 31, 2010 that pertained to prior periods, gas sales volumes for the two most current years were comparable.

Production Expenses. Production expenses are comprised of the following items:

	Year Ended March 31,
		2011		2010

Lease operating expenses	$	1,874,000	$	1,680,000
Workover costs		856,000		452,000
Production taxes		586,000		498,000
Transportation and other expenses		211,000		312,000

	$	3,527,000	$	2,942,000

Oil and natural gas production expense increased $585,000 (20%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. The two principal components of oil and gas production expense are 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 expense from period to period.

Workover expense increased $404,000 (89%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. This increase is primarily attributable to operations in the West Texas waterflood fields. Routine lease operating expense also increased $194,000 (12%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. Production taxes, which are a function of sales revenue, increased $88,000 for the year ended March 31, 2011, as compared to the year ended March 31, 2010. Production taxes as a percent of oil and natural gas sales revenue remained steady at 7%.

The increase in the production expenses as described above were offset by the $101,000 (32%) decrease in transportation costs for the year ended March 31, 2011, as compared to the year ended March 31, 2010, as production was lower for the year ended March 31, 2011. The decline in production resulting in the decrease in transportation costs was nominally offset by such costs increasing for the industry during 2011.

The overall lifting cost (oil and natural gas production expense plus production taxes) per BOE increased 34% from $21.48 for the year ended March 31, 2010 to $28.83 for the year ended March 31, 2011. The increase primarily related to this increase in workover costs as described above. 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.

Other Expenses.

Depletion and depreciation expense decreased $56,000 (5%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010 due to the reduction in production. Depletion expense per BOE increased from $8.65 for the year ended March 31, 2010 to $9.24 for the year ended March 31, 2011.

General and administrative ("G&A") expense decreased $264,000 (15%) for the year ended March 31, 2011, as compared to the year ended March 31, 2010. This decrease was primarily due to reductions in professional fees, which included investor relations costs, legal fees, accounting fees and Sarbanes-Oxley expenses. As a percent of total sales revenue, G&A expense decreased from 24% for the year ended March 31, 2010 to 18% for the year ended March 31, 2011, as a result of greater revenues and cost reductions. G&A expense per BOE decreased 5% from $12.99 for the year ended March 31, 2010 to $12.38 for the year ended March 31, 2011.

Income Taxes. For the year ended March 31, 2011, we recorded income tax expense of $206,000. This amount consisted of a current period expense of $104,000, and deferred tax expense of $102,000. Our effective income tax rate decreased from 12.57% for the year ended March 31, 2010 to 11.41% for the year ended March 31, 2011. Our effective income tax rate was lower for the year ended March 31, 2011, primarily due to an increase in deferred tax assets from the amounts originally estimated on the prior year tax provision.

Critical Accounting Policies and Estimates

See Note 1 to the consolidated financial statements.

Recent Accounting Pronouncements

In December 2008, the SEC decreed modified instructions for reporting oil and gas activities. The rule, effective and adopted for the Company’s year ended March 31, 2010, changes the oil and natural gas prices used to calculate reserve quantities and the full cost ceiling limitation from the spot price on the last day of the reporting period to the 12 month average prices, calculated as the unweighted arithmetic average price of oil and gas on the first day of each month for each of the 12 months prior to the last day of the reporting period (unless prices are defined by contractual arrangements). Adoption of this rule impacted depletion expense for the year ended March 31, 2010, as well as the ceiling test calculation for oil and gas properties as of March 31, 2010. Adoption of this rule for the year ended March 31, 2010 is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of this guidance, other than pricing, significantly impacted the financial statements, and it is impracticable to estimate the effect of applying the new rule on net income or the amount recorded for depletion for the year ended March 31, 2010.

In January 2010, the Financial Accounting Standards Board expanded the required disclosure of fair value measurements, requiring disclosure of the amounts and reasons for significant transfers between Level 1 and Level 2 of the fair value hierarchy, and disaggregation in the reconciliation for fair value measurements using significant unobservable inputs to separately provide information about purchases, sales, issuances and settlements. Effective for the Company’s year ended March 31, 2010, additional disclosure is also required about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring measurements. Adoption of this amendment, which solely amends disclosure requirements, results in no impact to the Company’s financial position, results of operations, or cash flows.

Various other accounting pronouncements have been recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to have a material effect on our financial position, results of operations, or cash flows.

Off Balance Sheet Arrangements

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

ITEM 7A

QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

As a “smaller reporting company,” we are not required to provide the information.

ITEM 8

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Earthstone Energy, Inc.

Table of Contents

Consolidated Financial Statements

and Accompanying Notes

March 31, 2011 and 2010

	Page

Report of Independent Registered Public Accounting Firm – Ehrhardt Keefe Steiner & Hottman PC		32

Consolidated Balance Sheets		33-34

Consolidated Statements of Operations		35

Consolidated Statements of Shareholders’ Equity		36

Consolidated Statements of Cash Flows		37

Notes to Consolidated Financial Statements		38-51

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Earthstone Energy, Inc.

Denver, Colorado

We have audited the accompanying consolidated balance sheets of Earthstone Energy, Inc. and Subsidiaries (the “Company”) as of March 31, 2011 and 2010, and the related statements of operations, shareholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits 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 audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Earthstone Energy, Inc. as of March 31, 2011 and 2010, and the results of their operations and their cash flows for the years then ended 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 and the ceiling test calculation for oil and gas property.

/s/ Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado

June 15, 2011

Earthstone Energy, Inc.

Consolidated Balance Sheets

Page 1 of 2

	March 31,			March 31,
	2011			2010

Assets
Current assets:
Cash and cash equivalents	$	4,051,000		$	4,905,000
Accounts receivable:
Oil and gas sales		1,674,000			1,021,000
Joint interest and other receivables, net of allowance of $93,000 and $86,000, respectively		329,000			401,000
Other current assets		539,000			732,000

Total current assets		6,593,000			7,059,000

Oil and gas property, full cost method:
Proved property		35,379,000			33,915,000
Unproved property		3,112,000			1,555,000
Accumulated depletion and impairment		(24,713,000	)		(23,582,000	)

Net oil and gas property		13,778,000			11,888,000

Support equipment and other non-current assets, net of accumulated depreciation of $377,000 and $374,000, respectively		471,000			451,000

Total non-current assets		14,249,000			12,339,000

Total assets	$	20,842,000		$	19,398,000

See accompanying notes to consolidated financial statements.

Earthstone Energy, Inc.

Consolidated Balance Sheets

Page 2 of 2

	March 31,			March 31,
	2011			2010

Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	496,000		$	161,000
Accrued liabilities		1,167,000			1,836,000

Total current liabilities		1,663,000			1,997,000

Long-term liabilities:
Deferred tax liability		2,319,000			2,217,000
Asset retirement obligation		1,795,000			1,674,000

Total long-term liabilities		4,114,000			3,891,000

Total liabilities		5,777,000			5,888,000

Commitments

Shareholders’ Equity:
Preferred shares, $0.001 par value, 600,000 authorized and none issued or outstanding		—			—
Common shares, $0.001 par value, 6,400,000 shares authorized and 1,782,000 and 1,773,000 shares issued, respectively		18,000			18,000
Additional paid-in capital		23,020,000			22,945,000
Treasury shares, at cost, 76,000 and 65,000 shares, respectively		(373,000	)		(251,000	)
Accumulated deficit		(7,600,000	)		(9,202,000	)

Total shareholders’ equity		15,065,000			13,510,000

Total liabilities and shareholders’ equity	$	20,842,000		$	19,398,000

See accompanying notes to consolidated financial statements.

Earthstone Energy, Inc.

Consolidated Statements of Operations

		Year Ended
		March 31,
		2011			2010

Revenues:
Oil and gas sales	$	8,099,000		$	7,219,000
Well service and water disposal revenue		107,000			50,000

Total revenues		8,206,000			7,269,000

Expenses:
Oil and gas production		2,941,000			2,444,000
Production tax		586,000			498,000
Well service and water disposal expenses		11,000			43,000
Depletion and depreciation		1,165,000			1,221,000
Accretion of asset retirement obligation		166,000			166,000
General and administrative		1,515,000			1,779,000

Total expenses		6,384,000			6,151,000

Income from operations		1,822,000			1,118,000

Other income (expense):
Interest and other income		12,000			90,000
Interest and other expenses		(26,000	)		(32,000	)

Total other income (expense)		(14,000	)		58,000

Income before income taxes		1,808,000			1,176,000

Current income tax expense		104,000			172,000
Deferred income tax expense (benefit)		102,000			(24,000	)

Total income tax expense		206,000			148,000

Net income	$	1,602,000		$	1,028,000

Per share amounts:
Basic	$	0.94		$	0.60
Diluted	$	0.94		$	0.60

Weighted average common shares outstanding:
Basic		1,710,453			1,707,353
Diluted		1,710,453			1,707,353

See accompanying notes to consolidated financial statements.

Earthstone Energy, Inc.

Consolidated Statements of Shareholders’ Equity

Years Ended March 31, 2011 and 2010

					Additional
	Common shares				paid-in		Treasury shares						Accumulated
	Shares		Amount		capital		Shares			Amount			deficit			Total

March 31, 2009		1,753,000	$	18,000	$	22,825,000		(38,000)		$	(43,000)		$	(10,230,000)		$	12,570,000

Purchase of treasury shares		—		—		—		(27,000)			(208,000)			—			(208,000	)
Share based compensation		20,000		—		120,000		—			—			—			120,000
Net income		—		—		—		—			—			1,028,000			1,028,000

March 31, 2010		1,773,000	$	18,000	$	22,945,000		(65,000	)	$	(251,000	)	$	(9,202,000	)	$	13,510,000

Purchase of treasury shares		—		—		—		(11,000)			(122,000)			—			(122,000	)
Share based compensation		9,000		—		75,000		—			—			—			75,000
Net income		—		—		—		—			—			1,602,000			1,602,000

March 31, 2011		1,782,000	$	18,000	$	23,020,000		(76,000	)	$	(373,000	)	$	(7,600,000	)	$	15,065,000

See accompanying notes to consolidated financial statements.

Earthstone Energy, Inc.

Consolidated Statements of Cash Flows

	Year Ended
	March 31,
	2011			2010

Cash flows from operating activities:
Net income	$	1,602,000		$	1,028,000
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion and depreciation		1,165,000			1,221,000
Deferred tax expense (benefit)		102,000			(24,000	)
Accretion of asset retirement obligation		166,000			166,000
Payments on asset retirement obligation		(283,000			(134,000	)
Share based compensation		75,000			72,000

Change in:
Accounts receivable, net		(581,000			419,000
Other current assets		193,000			(224,000	)
Accounts payable, accrued and other liabilities		185,000			142,000

Net cash provided by operating activities		2,624,000			2,666,000

Cash flows from investing activities:
Oil and gas property		(3,302,000	)		(1,612,000	)
Support equipment		(54,000	)		(29,000	)

Net cash used in investing activities		(3,356,000	)		(1,641,000	)

Cash flows from financing activities:
Purchase of treasury shares		(122,000	)		(208,000	)

Net cash used in financing activities		(122,000	)		(208,000	)

Net (decrease) increase in cash and cash equivalents		(854,000	)		817,000

Cash and cash equivalents, beginning of year		4,905,000			4,088,000

Cash and cash equivalents, end of period	$	4,051,000		$	4,905,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	―		$	17,000
Cash paid for income taxes	$	204,000		$	7,000
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	265,000		$	54,000
Vested shares issued as compensation	$	74,000		$	48,000
Accrued capital expenditures	$	141,000		$	687,000

See accompanying notes to consolidated financial statements.

Earthstone Energy, Inc.

Notes to Consolidated Financial Statements

March 31, 2011

1. Summary of Significant Accounting Policies

Organization and Nature of Operations. Earthstone Energy, Inc. was originally organized in July 1969 as Basic Earth Science Systems, Inc. and changed its name in 2010 to Earthstone Energy, Inc. The Company is principally engaged in the acquisition, exploration, development, and production of crude oil and natural gas properties, primarily operating in the Williston basin in North Dakota and Montana, south Texas and the Denver-Julesburg basin in Colorado.

Principles of Consolidation. The consolidated financial statements include the accounts of Earthstone Energy, Inc. and its wholly-owned subsidiary. All significant intercompany accounts and transactions have been eliminated. The Company does not have any unconsolidated special purpose entities.

At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout this document they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

Basis of Presentation. The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP").

Oil and Gas Sales. We derive revenue primarily from the sale of produced natural gas and crude oil. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's interest. Revenues are reported 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 and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between 30 and 90 days after the date of production. Estimates of the amount of production delivered to purchasers and the prices at which it was delivered are necessary at year end. Management’s knowledge of the Company’s properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors are 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 Reserves. Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate 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 the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

Oil and Gas Property. The Company uses the full cost method of accounting for costs related to its oil and gas property. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition and exploration activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas property unless nonrecognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs are subject to a ceiling test, as prescribed by Securities and Exchange Commission (“SEC”) regulations, that limits such pooled costs to the aggregate of the present value of future net cash flows attributable to proved oil and gas reserves, less future cash outflows associated with the asset retirement obligation that have been accrued plus the lower of cost or estimated fair value of unproved properties not being amortized less any associated tax effects. Prices are held constant for the productive life of each well. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, the excess is reflected as a non-cash charge to earnings. The write-down is permanent and not reversible in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase the ceiling amount. As of the balance sheet date, capitalized costs did not exceed the ceiling test limit.

For the years ended March 31, 2011 and 2010, the oil and natural gas prices used to calculate the full cost ceiling limitation are the 12 month average prices, calculated as the unweighted arithmetic average price of oil and gas on the first day of each month for each of the 12 months prior to the last day of the reporting period (unless prices are defined by contractual arrangements) and net cash flows are discounted at 10 percent.

Prior to March 31, 2010, ceiling calculations were based on the spot price on the last day of the reporting period. This change is a result of SEC requirements for reporting oil and gas activities effective for annual reporting periods ending on or after December 31, 2009. This rule, titled "Modernization of Oil and Gas Reporting" was implemented by the Company effective March 31, 2010.

Adoption of this rule impacted depletion expense for the year ended March 31, 2010, as well as the ceiling test calculation for oil and gas properties as of March 31, 2010. The rule further impacted the oil and gas reserve quantities that were estimated by the reservoir engineer. Adoption of this rule for the year ended March 31, 2010 is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of this guidance, other than pricing, significantly impacted the financial statements, and it is impracticable to estimate the effect of applying the new rule on net income or the amount recorded for depletion for the year ended March 31, 2010.

Unproved properties are excluded from the ceiling test. Instead, these property costs 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 of oil and gas property, excluding those pertaining to unproved properties, are depleted on a composite units-of-production method based on estimated proved reserves. For depletion purposes, the volume of reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Depletion expense per equivalent barrel of production was $9.24 and $8.65 for the years ended March 31, 2011 and 2010, respectively.

Oil and Gas Production Costs. Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Production costs (also referred to as lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities, and severance taxes.

Asset Retirement Obligation. The Company's activities are subject to various laws and regulations, including legal and contractual obligation to plug, reclaim, remediate, or otherwise restore oil and gas property at the time such asset ceases to be productive. An asset retirement obligation ("ARO") is initially measured at fair value and recorded as a liability with a corresponding asset when incurred if a reasonable estimate of fair value can be made. This is typically when a well is completed or an asset is placed in service. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the full cost pool. Over time, the liability increases for the change in its present value (and accretion expense is recorded), while the capitalized cost decreases by way of depletion of the full cost pool. Estimates are reviewed quarterly and adjusted in the period in which new information results in a change of estimate.

Income Taxes. Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions were identified as of any date on or before March 31, 2011. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of March 31, 2011, the Company has not recognized any interest or penalties related to uncertain tax benefits. For further information, see Note 8 below.

Earnings Per Share. Basic and diluted earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period, after giving effect to the 1-for-10 reverse stock split effective December 31, 2010. As of the balance sheet date, no dilutive securities were outstanding.

Cash and Cash Equivalents. All highly liquid investments with original maturities of ninety days or less are considered to be cash equivalents. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.

Fair Value Measurements. Financial instruments and nonfinancial assets and liabilities, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board, prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments.

As discussed in Note 5, the Company incurred asset retirement obligations of $49,000 and $54,000 during the years ended March 31, 2011 and 2010, respectively, the value of which was determined using unobservable pricing inputs (or Level 3 inputs). The Company uses the income valuation technique to estimate the fair value of the obligation using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement.

Hedging Activities. We had no hedging activities in the years ended March 31, 2011 and 2010. 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. Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. 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 to be used in future drilling operations or repair operations, is stated at the lower of cost or market, cost being determined by the FIFO method. See also Notes 2 and 3 below.

Commitments. The Company is committed to a total of $281,000 plus maintenance fees for a five-year lease term ending April 30, 2013 on a 4,000 square foot office space located in downtown Denver, Colorado. The Company does not have any off-balance sheet financing transactions, arrangements or obligations.

Major Customers and Operating Region. The Company operates exclusively within the United States of America. All of the Company's assets are employed in and all of its revenues are derived from the oil and gas industry. Individual external purchasers of 10% or more of the Company’s oil and gas production revenue for the years ended March 31, 2011 and 2010 were as follows:

	2011	2010

Valero Energy Corp.	19%	16%
Nexen Marketing USA, Inc.	9%	10%
Total	28%	26%

For the years ended March 31, 2011 and 2010, approximately 48% and 57%, respectively, of Earthstone’s oil and gas revenue was from non-operated properties where the Company has no direct contact with the actual purchaser. On these properties, Earthstone’s portion of the product was marketed by the 23 different companies who operate these wells. These 23 companies may, unbeknownst to us, market to one or more of the same purchasers to whom we sell directly. 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 these purchasers, it has been estimated that the reduction in annual revenue would be less than 10%. It is not expected that the loss of any one of these purchasers would cause a material adverse impact on the Company’s results from operations, as alternative markets for oil and gas production are readily available.

Bad Debt Expense. A charge is recognized in general and administrative expenses and an allowance is established against specific receivable balances from joint interest owners in instances where working interest owners dispute amounts billed for their proportionate share in the cost of wells which the Company operates. As individual disputes are resolved, either the expense is reversed in the period of the resolution or the receivable is written down.

Share Based Compensation. The Company recognizes all equity based compensation as share based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date. The expense is recognized over the vesting period of the grant. See Note 7 below for information.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions concern matters that are inherently uncertain. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from those estimates.

Reclassifications. Certain prior year amounts were reclassified to conform to current presentation. Such reclassifications had no effect on the prior year net income, accumulated deficit, net assets or total shareholders' equity.

Recent Accounting Pronouncements

Subsequent Events

For the period ended March 31, 2011, there were no subsequent events to recognize or disclose in the consolidated financial statements which would either impact the results reflected in this report or the Company’s results going forward.

2. Other Current Assets

Other current assets as of March 31, 2011 and 2010 consisted of the following:

		2011		2010

Lease and well equipment inventory	$	399,000	$	399,000
Drilling and completion cost prepayments		24,000		244,000
Prepaid insurance premiums		16,000		49,000
Prepaid income taxes		81,000		21,000
Other current assets		19,000		19,000

Total other current assets	$	539,000	$	732,000

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 for the years ended March 31, 2011 and 2010 consisted of the following:

		2011		2010

Support equipment and lease and well equipment inventory	$	281,000	$	272,000
Plugging bonds		60,000		60,000
Other non-current assets		130,000		119,000

Total support equipment and other non-current assets	$	471,000	$	451,000

Support equipment represents non-oil and gas property (including such items as vehicles, office furniture and equipment and well servicing equipment) and is stated at the lower of cost or market. Depreciation of support equipment was $34,000 and $36,000 for the years ended March 31, 2011 and 2010, respectively, which was computed using primarily the straight-line method over periods ranging from five to seven years.

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

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

4. Accrued Liabilities

Accrued liabilities for the years ended March 31, 2011 and 2010 consisted of the following:

		2011		2010

Revenue and production taxes payable	$	340,000	$	348,000
Accrued compensation		223,000		172,000
Accrued operations payable		239,000		820,000
Accrued income taxes payable and other		238,000		396,000
Short term asset retirement obligation		127,000		100,000

Total accrued liabilities	$	1,167,000	$	1,836,000

5. Asset Retirement Obligation

For the purpose of determining the fair value of the asset retirement obligation incurred during the year ended March 31, 2011, the Company assumed an inflation rate of 4%, an estimated average asset life of 23.5 years, and a credit adjusted risk free interest rate of 8.4%.

The following reconciles the value of the asset retirement obligation for the periods presented. This included a short term obligation of $127,000 and $100,000 as of March 31, 2011 and 2010, respectively, which was a component of accrued liabilities on the balance sheet:

		2011			2010

Asset retirement obligation, beginning of period	$	1,774,000		$	1,698,000
Liabilities settled		(283,000	)		(134,000	)
Liabilities incurred		49,000			54,000
Accretion		166,000			166,000
Revisions to estimates		216,000			(10,000	)

Asset retirement obligation at, end of period	$	1,922,000		$	1,774,000

Less current portion	$	(127,000	)	$	(100,000	)

Asset retirement obligation, less current portion	$	1,795,000		$	1,674,000

6. Commitments

Office rent expense was approximately $113,000 and $107,000 for the years ended March 31, 2011 and 2010, respectively (including building maintenance charges). The Company is committed to a total of $157,000 for the remaining term ending April 30, 2013.

The Company also has commitments pertaining to software, phone and copy machine maintenance contracts totaling $84,000, $80,000, and $13,000 for the years ending March 31, 2012, 2013, and 2014, respectively.

7. Shareholders’ Equity

Reverse Stock Split. Effective December 31, 2010, the Board of Directors authorized and effected a 1-for-10 reverse stock split which converted ten (10) shares of the Company’s common stock into one (1) share of common stock. The Board of Directors also authorized and effected a 1-for-5 reverse stock split for the number of authorized common shares and preferred shares as follows: (a) the reduction of the number of authorized shares of common shares from the then authorized 32,000,000 shares down to 6,400,000 shares, and (b) the reduction of the number of authorized shares of preferred shares from the then authorized 3,000,000 shares down to 600,000 shares. Both the common and preferred shares maintain a par value of $0.001. All references to the number of common shares, treasury shares, and per share amounts in the accompanying consolidated financial statements reflect the reverse stock split.

Preferred Shares. The Company has 600,000 shares of authorized preferred stock with a par value of $0.001 available for issuance in such series and preferences as determined by the Board of Directors. Since inception, the Company has not issued any preferred shares.

Common Shares. The Company has authorized 6,400,000 shares of common stock with a par value of $0.001. The total issued common stock as of March 31, 2011, was 1,782,000 common shares.

Share Based Compensation. On March 8, 2007, the Board of Directors adopted a Director Compensation Plan (“the Plan”) allotting up to 50,728 shares of the Company’s common stock to be issued to independent, non-employee directors. In connection with the 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. Shares are subject to certain restrictions and vesting.

During the year ended March 31, 2011, 9,270 shares of common stock reserved for issuance under the Plan were authorized for issuance. Accordingly, as of March 31, 2011, 20,716 shares of common stock remain available for issuance under the Plan. Grants of shares of restricted stock vest one-third each year over three years. 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 March 31, 2011, for each non-employee director was as follows: Robertson – 8,555 shares; Rodgers – 8,555; and Calerich – 552. In addition, each of the three independent directors was granted 1,867 shares of restricted stock on April 1, 2011, subject to vesting and forfeiture. All restricted shares are considered issued and outstanding shares of the Company’s common stock at the grant date and have the same dividend and voting rights as other common stock.

On January 4, 2011, the Board of Directors authorized the Company to increase the Board of Directors to four members in accordance with the Bylaws. On January 6, 2011, Andrew P. Calerich was appointed a seat on the Board of Directors and was granted restricted common stock valued at $9,000, subject to a vesting period similar to other directors, ergo the aforementioned 552 restricted shares. Consistent with the calculation of shares for the annual grant of stock to directors, the number of restricted shares was determined by the average closing share price for the last ten trading days of the quarter ended December 31, 2010. This price, adjusted for the reverse stock split, was $16.30.

A summary of the status of the Company’s nonvested shares under the Director Compensation Plan as of March 31, 2011 and 2010, and changes during the years ended on those dates is presented below:

	2011						2010
				Weighted						Weighted
				Average						Average
				Grant Date Fair						Grant Date Fair
	Shares			Value			Shares			Value

Nonvested shares, beginning of year		15,306		$	144,000			10,244		$	120,000

Granted		9,270			81,000			8,982			72,000
Vested		(6,914	)		(72,000	)		(3,920	)		(48,000	)
Forfeited		—			—			—			—

Nonvested shares, end of year		17,662		$	153,000			15,306		$	144,000

As of March 31, 2011, there was $80,000 of total unrecognized compensation cost related to nonvested share based compensation arrangements granted under the Director Compensation Plan. That cost is expected to be recognized over a weighted-average period of 1.02 years.

The Company granted one key employee 624 restricted shares of Company common stock during the year ended March 31, 2010, valued at $5,000. Such shares vest one-third each year over three years, subject to forfeiture.

Share based compensation expense of $75,000 and $72,000 was recognized during the years ended March 31, 2011 and 2010, respectively, for restricted share grants to independent directors.

Treasury Shares. On October 22, 2008, the Company’s Board of Directors authorized a share buyback program for the Company to repurchase up to 50,000 shares of its common stock for a period of up to 18 months. The program 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 150,000. 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, 2011, 10,997 shares were repurchased under the share buyback program and 109,440 shares remain available for future repurchase. No treasury shares have been retired.

8. Income Taxes

The provision for income taxes for the years ended March 31, 2011 and 2010 is comprised of the following:

	2011		2010
Current:
Federal	$	93,000	$	171,000
State		11,000		1,000
Total current income tax expense		104,000		172,000

Deferred:
Federal		95,000		(23,000	)
State		7,000		(1,000	)
Total deferred income tax expense (benefit)		102,000		(24,000	)

Income tax expense	$	206,000	$	148,000

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, 2011 and 2010 follows:

	2011			2010

Federal taxes at statutory rate	$	615,000		$	400,000
State taxes, net of federal benefit		26,000			9,000
Excess percentage depletion		(270,000	)		(283,000	)
Adjustments to deferred tax assets related to intangible drilling costs		(148,000	)		—
Non-deductible permanent items		—			6,000
Other adjustments, net		(17,000	)		16,000

Income tax expense	$	206,000		$	148,000
Effective tax rate expressed as a percentage of income before income taxes		11	%		13	%

The overall effective tax rate expressed as a percentage of book income before income taxes for year ended March 31, 2011, as compared to the ended March 31, 2010, was lower due to the Company having an increase in deferred tax assets from the amounts originally estimated on the prior year tax provision.

Net income tax payments were $204,000 and $7,000 for the years ended March 31, 2011 and 2010, respectively.

Net deferred tax assets and liabilities for the years ended March 31, 2011 and 2010 were comprised of:

	2011			2010
Deferred tax assets:
Allowance for doubtful accounts	$	34,000		$	31,000
Asset retirement obligation		703,000			647,000
Statutory depletion carry-forward		1,110,000			1,074,000

Gross deferred tax assets		1,847,000			1,752,000

Other accruals		69,000			47,000
Depletion, depreciation and intangible drilling costs		(4,235,000	)		(4,016,000	)

Gross deferred tax liabilities		(4,166,000	)		(3,969,000	)

Deferred tax assets (liabilities), net	$	(2,319,000	)	$	(2,217,000	)

Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred tax assets and liabilities are continually re-evaluated and numerous estimates are revised over time. As such, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.

The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are the years ended March 31, 2007 through 2010.

9. Related Party Transactions

The Company maintains a policy permitting officers or directors to assign to the Company or receive assignments from the Company in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. This policy also allows officers or directors and the Company to participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by non-related third parties. In 2010, Ray Singleton, Earthstone’s President and Chief Executive Officer, 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 the years ended March 31, 2011 and 2010, no other director or officer participated with the Company in any oil and gas transaction. In prior years, Mr. Singleton has participated with the Company in the acquisition of producing properties on the same terms and conditions as 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 has an ownership, as of March 31, 2011, the Company had an accrued balance due from Mr. Singleton of $11,000 for his share of operating expenses on these wells, which was billed ten days after year end and for which timely payment was subsequently received. As of March 31, 2010, as a result of his share of oil and gas revenue exceeding the amount of his share of operating expenses, the Company had a balance of $10,000 due to Mr. Singleton.

10. Oil and Gas Property

The aggregate amount of capitalized costs related to oil and gas property and the aggregate amount of related accumulated depletion as of March 31, 2011 and 2010 are as follows:

		2011			2010

Proved property	$	35,379,000		$	33,915,000
Unproved property		3,112,000			1,555,000

Total capitalized oil and gas property		38,491,000			35,470,000
Accumulated depletion and impairment		(24,713,000	)		(23,582,000	)

Net capitalized oil and gas property	$	13,778,000		$	11,888,000

The following shows, by category and year incurred, the oil and gas property costs applicable to unproved property that were excluded from the full cost pool depletion computation as of March 31, 2011:

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

March 31, 2011	$	—	$	1,216,000	$	756,000	$	1,972,000
March 31, 2010		1,000		361,000		73,000		435,000
Prior Years		—		—		705,000		705,000

Total	$	1,000	$	1,577,000	$	1,534,000	$	3,112,000

Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2011 and 2010 are summarized as follows:

		2011		2010

Development costs	$	1,454,000	$	1,223,000
Exploration costs		—		620,000
Acquisitions:
Proved		519,000		—
Unproved		756,000		313,000

Total costs of development, exploration and acquisition activities	$	2,729,000	$	2,156,000

11. Unaudited Oil and Gas Reserves Information

As of March 31, 2011 and 2010, 91% 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 9% and 7% of the reserve estimates, respectively, were prepared internally by the Company’s management.

Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered through wells yet to be completed.

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

Proved Reserves

	March 31, 2011						March 31, 2010						March 31, 2009
	Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)
Proved reserves:
Balance, beginning of year		818,000			912,000			638,000			936,000			1,074,000			1,120,000
Revisions of previous estimates¹		167,000			(106,000	)		275,000			195,000			(429,000	)		(262,000	)
Extensions and discoveries²		62,000			39,000			4,000			10,000			86,000			253,000
Improved recovery		6,000			61,000			—			—			—			—
Purchase of reserves		55,000			1,000			—			—			—			—
Production³		(93,000	)		(172,000	)		(99,000	)		(229,000	)		(93,000	)		(175,000	)

Balance, end of year		1,015,000			735,000			818,000			912,000			638,000			936,000

Proved developed reserves:
Balance, beginning of year		727,000			912,000			587,000			907,000			1,074,000			1,120,000

Balance, end of year		1,015,000			735,000			727,000			912,000			587,000			907,000

Proved undeveloped reserves:
Balance, beginning of year		91,000			—			51,000			29,000			—			—

Balance, end of year		—			—			91,000			—			51,000			29,000

Revisions of Previous Estimates – Estimates reflect steady increases in oil and gas prices since December 2008, when prices reached a 5-year low. Changes in performance constitute less than 10% of the total amount of revisions of previous estimates.

Extensions and Discoveries – Eleven wells represent extensions and discoveries during the year ended March 31, 2011, in North Dakota (7), Montana (2), Colorado (1) and Texas (1). Additions during the year ended March 31, 2010, consisted of 2 new wells in Colorado and 1 new well in North Dakota. Additions during the year ended March 31, 2009, pertained to the 16 wells drilled in Colorado.

Production – Volumes of oil and gas that were produced were removed from reserves during the year.

The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved oil and gas reserves. Estimated future cash inflows were computed by applying the 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 as of March 31, 2011 and 2010. Estimated future cash flows for the year ended March 31, 2009 were based on the spot price on the last day of the reporting period. This change is a result of the modified instructions from the SEC for reporting oil and gas activities, as explained in Note 1 above, effective and adopted for the Company’s year ended March 31, 2010. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

Standardized Measure of Estimated Discounted Future Net Cash Flows

		For the Years Ended March 31,
		2011			2010			2009

Future cash inflows	$	81,053,000		$	55,991,000		$	31,793,000
Future cash outflows:
Production cost		(41,185,000	)		(29,065,000	)		(17,924,000	)
Development cost		—			(991,000	)		(490,000	)
Future income taxes		(6,545,000	)		(3,361,000	)		(2,100,000	)

Future net cash flows		33,323,000			22,574,000			11,279,000
Adjustment to discount future annual net cash flows at 10%		(15,826,000	)		(10,060,000	)		(4,080,000	)

Standardized measure of discounted future net cash flows	$	17,497,000		$	12,514,000		$	7,199,000

The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for each of the years ended March 31, 2011, 2010, and 2009:

Changes in Standardized Measure of Estimated Discounted Net Cash Flows

		For the Years Ended March 31,
		2011			2010			2009

Standardized measure, beginning of period	$	12,514,000		$	7,199,000		$	24,960,000
Sales of oil and gas, net of production cost		(5,204,000	)		(4,284,000	)		(5,808,000	)
Net change in sales prices, net of production cost		5,886,000			6,279,000			(25,977,000	)
Discoveries, extensions and improved recoveries, net of future development cost		1,567,000			154,000			2,298,000
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		3,806,000			5,280,000			(4,745,000	)
Accretion of discount		1,874,000			720,000			4,279,000
Net change in income taxes		3,685,000			(1,582,000	)		16,594,000
Purchase of reserves		1,408,000			—			—
Changes in timing of rates of production		(8,039,000	)		(1,719,000	)		(4,402,000	)

Standardized measure, end of period	$	17,497,000		$	12,514,000		$	7,199,000

ITEM 9

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the phrase “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 controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2011. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Interim Chief Financial Officer concluded that, as of March 31, 2011, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Annual Report on Internal Control Over Financial Reporting

The management of 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's assets that could have a material effect on the financial statements.

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.

Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Interim Chief Financial Officer, we conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of March 31, 2011.

Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to 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.

ITEM 9B

OTHER INFORMATION

None.

Part III

ITEM 10

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2011 annual shareholders’ meeting and is incorporated by reference in this report.

ITEM 11

EXECUTIVE COMPENSATION

ITEM 12

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

ITEM 13

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

AND DIRECTOR INDEPENDENCE

ITEM 14

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Part IV

ITEM 15

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	Documents filed as part of this Annual Report on Form 10-K.

	(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
3(i)a		Restated Certificate of Incorporation of 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)b		Amended and Restated Certificate of Incorporation as approved by shareholders of the Company at the Company’s 2009 Annual Meeting of Shareholders and the amendments to the Company’s Certificate of Incorporation previously disclosed in the 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(i)c		Certificate of Amendment to Certificate of Incorporation dated December 20, 2010 are incorporated by reference to Exhibit 3(i) on Form 8-K filed with the SEC on January 4, 2011.
3(ii)a		Bylaws 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)b		Amended and Restated Bylaws reflecting 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, shareholder 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 shareholders’ 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.

4.1		Rights 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.
4.2		Specimen Stock Certificate of Earthstone Energy, Inc., filed herewith.
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 year ended March 31, 1985, filed with the SEC.
10.3*		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, incorporated by reference to Exhibit 10.4 of our Annual Report on Form 10-K for the year ended March 31, 2010, filed with the SEC on June 18, 2010.
10.5*		Form of Restricted Stock Agreement pursuant to the Director Compensation Plan, incorporated by reference to Exhibit 10(ii) of the Annual Report on Form 10-KSB for the year ended March 31, 2008, filed with the SEC on July 11, 2008.
10.6*		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.
10.7*		Financial Consulting Agreement, effective March 16, 2011, between QAS, LLC and Earthstone, filed herewith.
14.1		Code of Business Conduct and Ethics, incorporated by reference to Exhibit 14.1 of our Annual Report on Form 10-KSB/A for the year ended March 31, 2004, filed with the SEC on May 11, 2005.
21		Subsidiary List, incorporated by reference to Exhibit 21 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).
31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial Officer).
32.1		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).
32.2		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial 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.
99.2		Compensation Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.2 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
99.3		Report of Ryder Scott Company, filed herewith.

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

Signatures

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

EARTHSTONE ENERGY, INC.


		Date

By: /s/ Ray Singleton		June 15, 2011
Ray Singleton, President and Chief Executive Officer

By: /s/ Jim Poage		June 15, 2011
Jim Poage, Interim Chief Financial 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 15, 2011
Ray Singleton, Director

By: /s/ Richard K. Rodgers		June 15, 2011
Richard K. Rodgers, Director and
Compensation Committee Chairman

By: /s/ Monroe W. Robertson		June 15, 2011
Monroe W. Robertson, Director and
Audit Committee Chairman

By: /s/ Andrew P. Calerich		June 15, 2011
Andrew P. Calerich, Director

Attached files

EARTHSTONE ENERGY INC Reports

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