•●	our ~~stragegies,~~strategies, 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;~~ expenditures, including future share repurchases;
•●	acquisitions and other business opportunities;
•●	operating costs and other expenses, including asset retirement obligation expenses;
•●	wells expected to be drilled, other anticipated exploration efforts and ~~the expenses~~ associated ~~therewith;~~ expenses;
•	~~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;~~ requirements; and
•●	other estimates and assumptions we use in our accounting ~~policies; and~~
•	~~future share repurchases.~~ policies.

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

•●	loss of senior management or technical personnel;
●	oil and natural gas ~~prices;~~ prices and production costs;
•●	our ability to replace oil and natural gas ~~reserves;~~
•	~~loss of senior management or technical personnel;~~
•	~~inaccuracy~~reserves, including changes in reserve estimates resulting from expected oil and ~~expected~~gas prices, production ~~rates;~~ rates, tax rates and production costs;
•●	exploitation, development, production and exploration ~~results;~~results, including mechanical failure;
•	~~mechanical failure;~~
•●	the ~~actual~~estimated costs ~~related to~~of asset retirement obligation, ~~and~~including whether or not those ~~retirements~~retirement costs, in whole or in part, are ever actually ~~occur~~incurred in the future;
•●	the potential unavailability of drilling rigs and other field equipment and services;
•●	the existence of unanticipated liabilities ~~or problems~~ relating to existing properties or those acquired ~~properties;~~ in the future, including environmental liabilities;
•●	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;~~
•	conditions, including any change in interest rates or inflation;
•●	athe 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
• ●	weather or 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.

“Disposal well” – A well used for the disposal of water resulting from the production of oil and gas. Oil and gas reservoirs are usually found in porous rocks, which also contain saltwater. This saltwater, which accompanies the oil and gas to the surface, is disposed over time through injection into underground porous rock formations not productive of oil or gas.

“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.

“Injector well” – A well used for the injection of water, gas, steam or CO2 into an oil-or gas producing reservoir/unit in order to maintain reservoir pressure, heat the oil or lower its viscosity, in order to increase oil and /or gas recovery and to safely dispose of the salt and/or fresh water produced with oil and natural gas.

“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~~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 oil and 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 synonym for “fracturing.” A process that results in the creation of fractures in rocks. The fracturing is done from a wellbore drilled into reservoir rock formations at depth 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 or percentage of ~~interest owned in the~~ revenue/proceeds derived from a producing well ~~less all royalty interests.~~that the owner is entitled to receive.

“Working interest” – The ~~operating interest~~amount or percentage of costs that an owner is required to pay of drilling and production expenses. It also gives the ~~owner~~owners, in the aggregate, 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.~~property.

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~~2012

Table of Contents

	Part I		Page

Item 1	Description of Business	10		7
Item 1A	Risk Factors	15		12
Item 1B	Unresolved Staff Comments	15		12
Item 2	Description of Property	15		12
Item 3	Legal Proceedings	20		16

	Part II

Item 5	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	21		17
Item 6	Selected Financial Data	23		20
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	24		20
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	30		25
Item 8	Financial Statements and Supplementary Data	31		26
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	52		47
Item 9A	Controls and Procedures	52		47
Item 9B	Other Information	53		47

	Part III

Item 10	Directors, Executive Officers and Corporate Governance	54		48
Item 11	Executive Compensation	54		48
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	54		48
Item 13	Certain Relationships and Related Transactions and Director Independence	54		48
Item 14	Principal Accountant Fees and Services	54		48

	Part IV

Item 15	Exhibits, Financial Statement Schedules	55		49
	Signatures	57		51

Part I

ITEM 1

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.~~south Texas. As of March 31, ~~2011,~~2012, our estimated net proved oil and natural gas reserves were ~~1,015,000~~1,227,000 Bbls of oil and condensate and ~~735,000~~646,000 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.

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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 increase our operational capability and 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.~~this calendar year. These areas are the Banks ~~Field~~and Bonetrail Fields in McKenzie County, North Dakota, and the ~~Mondak~~Rush Mountain 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 both on existing ~~properties.~~properties and new prospects.

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~~we completed and ~~SM Energy, have drilled five~~brought onto production ten wells on the prospect. ~~Two~~Six such wells are ~~now on production (the Pederson 10-3H~~being operated by Brigham Exploration Company. Zenergy Inc. is the operator of three of these wells 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~~the last is being operated by SM Energy Company. We, with our strategic partners, are committed to ~~drill ten~~drilling an additional dozen wells on this acreage before calendar year ~~end and~~end. As of June 1, 2012, we have ~~already~~ executed AFEs authorizing the drilling of ~~six of the possibly~~ ten ~~wells.~~wells being operated by Brigham, one well by Zenergy, and one well by Continental.

~~Mondak~~Indian Hill Field — McKenzie County, North Dakota. ~~The Company has an interest in three~~With improving hydraulic stimulation technology, a number of Bakken horizontal wells ~~in the Mondak Field. One of these wells was~~have been drilled in the area. We participated in the drilling of three such horizontal wells this year, ~~ended March 31, 2011. This well, the Mondak Federal 24X-12, is still being completed and not yet~~all of which are on production. ~~This acreage is currently developed for one well per spacing unit. However, we~~We anticipate that this acreage will be developed for two wells per spacing unit in the ~~future.~~coming year.

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~~Bailey Field — Dunn County, North Dakota. Prior to the year ended March 31, 2012, Earthstone had an interest in two producing wells in the Dunn County. During the year ended March 31, 2012, the Company participated with Marathon in the drilling of two additional wells, both of which were producing by year end.

Mondak Field — McKenzie County, North Dakota. The Company ~~holds approximately 960 gross (192 net) acres~~has an interest in three horizontal Bakken wells in the ~~Indian Hill Field. With improving hydraulic stimulation technology, a number~~Mondak Field, all of ~~Bakken horizontal wells have been drilled in the area. We~~which are producing wells. This acreage is currently developed for one well per spacing unit. However, we anticipate that this acreage will be ~~proposed~~developed for ~~horizontal Bakken development~~two wells per spacing unit in the ~~coming year.~~future.

Divide County, North Dakota — Sheridan County, Montana. ~~Recently,~~In the past year, several companies have drilled horizontal Bakken wells in these two counties, ~~in the Bakken Shale,~~ resulting in strong production figures. ~~Also~~In Sheridan county, in 2011 and 2012, the Company acquired three producing wells in each year, along with each wells’ associated acreage. In addition, in the ~~third and fourth quarter~~Rush Mountain Field 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~~we participated with Vess Oil Corporation in the drilling of ~~these acquisitions, in addition to~~a horizontal Ratcliffe well at a 10% ownership level. This well is currently being completed and results are not yet available. In the ~~legacy producing properties in these two counties, along with undeveloped leasehold acreage,~~current year, the Company ~~has an~~ ~~estimated 15,200 gross (4,000 net) acres which could be evaluated for horizontal Bakken development~~expects to participate in the ~~coming years.~~drilling of an additional well on this prospect.

118

~~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,~~2012, our proved reserves in BOE and PV-10 increased approximately 17% and ~~42%~~50%, respectively (from March 31, ~~2010)~~2011). 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,~~2012, approximately ~~48%~~43% of our oil and natural gas production revenues were received from sales to nine purchasers (compared to ~~43%~~48% to ~~six~~nine purchasers in the previous fiscal year). The remaining ~~52%~~57% 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 2321 different companies who operate these wells. These 2321 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,~~2012, we had ~~eight~~eleven full-time, two part-time employees and ~~two~~four 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~~

While the Company engages in hydraulic fracturing activities, this method of stimulating oil and gas production has been in use since the 1940s, and is a common and proven technology used in exploration and production by the oil and gas industry in all oil and gas producing states without any known or significant risks to the environment. In this regard, it should be noted that the Environmental Protection Agency amended the Underground Injection Control provisions of the ~~disposal~~federal Safe Drinking Water Act to exclude hydraulic fracturing from the definition of “underground injection.” Furthermore, each state has comprehensive laws and regulations to provide for safe well construction practices and operations to ensure the protection of drinking water sources. To our knowledge, the Company is, and remains, in compliance with all Federal, State and local provisions which have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. With regards to the magnitude of the Company’s use of hydraulic fracturing of oil & gas wells, Earthstone holds a minority interest in a number of wells that are under the management and control of far larger companies who apply various stimulation strategies. The Company’s ownership varies on these new drilling projects from 0.1% to 10% interest depending on the specific well. With these small interests, in the unlikely event that a containment failure were to occur on a single well, it is not likely that the event would have a material financial or operational impact on the Company.

Potential environmental effects may also arise from the use of disposal and injector wells. We hold a working interest in six disposal and six injector wells, eight of which we ~~utilize~~operate, the

remaining of which 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.”

1411

ITEM 1A

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

1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2

2. DESCRIPTION OF PROPERTY

Producing Properties: Location and Impact

As of March 31, ~~2011,~~2012, we owned a working interest in 83118 gross producing oil wells, ~~and 44~~3 gross producing gas wells, 6 disposal wells and 6 injector wells in six states: North Dakota, Montana, ~~Colorado,~~ Texas, Louisiana, Colorado and Wyoming.

Productive Wells

	Gross Wells				Net Wells				Gross Wells				Net Wells
	Oil		Gas		Oil		Gas		Oil		Gas		Oil		Gas

North Dakota										57		2		9.13		0.04
Montana										27		-		9.65		-
Texas										31		-		27.36		-
Louisiana										2		-		0.11		-
Colorado		—		41		—		13.66		-		1		-		0.05
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		—		1		-		0.47		-

Total		83		44		41.86		13.91		118		3		46.72		0.09

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,~~2012, our estimated proved ~~developed and undeveloped~~ oil and natural gas reserves in barrels of oil equivalent (“BOE”) was ~~1,137,000,~~1,335,000, a 17% increase from the prior year end’s estimated proved oil and natural gas reserves of ~~970,000~~1,137,000 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 reported reserves are located in ~~three~~two primary areas: the Williston basin in North Dakota and Montana ~~the Denver-Julesburg (“D-J”) basin in Colorado~~ and onshore south Texas. While we hold interests in producing wells outside of these two primary locations, we are not reporting reserves for such properties due to their insignificance.

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~~two areas as of March 31, ~~2011:~~

2012:

Estimated Proved Oil and Gas Reserves by Area

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

Williston Basin
Operated		176,763		75,763		189,390		16.7	%		165,029		97,161		181,223		13.6	%
Non-Operated		397,698		221,519		434,618		38.2	%		644,057		548,461		735,467		55.1	%
		574,461		297,282		624,008		54.9	%		809,086		645,622		916,690		68.7	%


South Texas/Onshore Gulf Coast
Operated		388,103		—		388,103		34.1	%		418,457		-		418,457		31.3	%
Non-Operated		—		—		—		—	%		-		-		-		-	%
		388,103		—		388,103		34.1	%		418,457		-		418,457		31.3	%


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	%		1,227,543		645,622		1,335,147		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~~All of our reported oil and natural gas reserves have been estimated as of March 31, ~~2011, for a significant portion of our properties~~2012, by the Ryder Scott Company (“Ryder Scott”) of Houston, Texas. As of March 31, 2011, Ryder Scott estimated reserves for properties located in the states of ~~Colorado, Louisiana,~~ Montana, North Dakota, and Texas, comprising ~~approximately 91% and 93%~~100% of the PV-10 of our oil and gas reserves as of ~~March 31, 2011 and 2010, respectively.~~that date. 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~~reserves estimates is registered in the state of Texas (License #F-1580). Ryder Scott prepared our ~~reserves estimates~~reserve estimate 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,~~25, 2012, 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.~~and pressure data available through March 31, 2012. The data used in this analysis was obtained from public data sources and was considered sufficient for calculating producing reserves. The proved undeveloped reserves were estimated by the analogy method. The analogy method uses pertinent well data obtained from public data sources that were available through March 31, 2012.

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.~~2012. All of our reserves are located in the United States.

Estimated Proved Developed and Undeveloped Oil and Gas Reserves

	Proved Developed								Proved Developed
	Producing		Non-Producing		Proved Undeveloped		Total Proved		Producing		Non-Producing		Proved Undeveloped		Total Proved

Net Remaining Reserves
Oil/Condensate – Bbls		1,015,000		―		―		1,015,000
Plant Products – Bbls		―		―		―		―
Oil/Condensate - Bbls										1,077,000		-		150,000		1,227,000
Plant Products - Bbls										-		-		-		-
Gas – Mcf		735,000		―		―		735,000		515,000		-		131,000		646,000

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~~wherein we present 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~~2012 and ~~2010.~~2011.

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, 2012, 2011 ~~2010,~~ and ~~2009,~~2010, respectively:

Exploratory and Developmental Wells Drilled

	2011		2010		2009		2012		2011		2010
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Exploratory
Productive
Oil	―	―	―	―	1	0.01	-	-	-	-	-	-
Gas	―	―	―	―	―	―	-	-	-	-	-	-
Dry holes	―	―	1	0.55	―	―	-	-	-	-	1	0.55

Total	―	―	1	0.55	1	0.01	-	-	-	-	1	0.55

Development
Productive
Oil	20	5.11	5	0.36	3	0.09	18	0.74	20	5.11	5	0.36
Gas	2	0.17	―	―	9	2.27	-	-	2	0.17	-	-
Dry holes	―	―	―	―	―	―	-	-	-	-	-	-

Total	22	5.28	5	0.36	12	2.36	18	0.74	22	5.28	5	0.36

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				Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net		Gross		Net		Gross		Net

Colorado		640		384		—		—
Louisiana		687		51		—		—		687		51		-		-
Montana		7,051		3,131		11,876		3,078		8,010		3,204		13,836		3,274
Nebraska		—		—		84,944		18,470		-		-		71,552		29,508
North Dakota		7,096		2,714		19,900		3,717		12,659		2,696		18,713		1,706
Texas		3,080		2,486		—		—		3,080		2,486		-		-
Utah										-		-		42,736		441
Wyoming		1,555		329		40		1		1,555		329		40		1
										-		-
Total		20,109		9,095		116,760		25,266		25,991		8,766		146,877		34,930

Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil.

Field Service Equipment

As of March 31, ~~2011,~~2012, our ~~remaining~~sole active subsidiary, Basic Petroleum Services, Inc. located in Bruni, Texas, owned a ~~trailer~~ house/field office, a shallow pulling rig, a backhoe, 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~~6,200 square feet of office space in downtown Denver, Colorado from an independent third party for approximately ~~$6,000~~$8,750 per month plus maintenance ~~fees escalating at a rate of approximately $170 at the end of each year.~~fees. The lease term ~~is for a five-year period ending April 30,~~ends on May 31, 2013. For additional information see Note 6 to the consolidated financial statements.

ITEM 3

3. LEGAL PROCEEDINGS

None.

2016

Part II

ITEM 5

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~~NYSE MKT under the ticker symbol “ESTE.” Prior to ~~January 26,~~December 20, 2011, our stock was traded on NASDAQ Global Select Market and prior to January 26, 2011, on the Over-the-Counter Bulletin Board (“OTCBB”) under the symbol “BSIC.”

The closing bid price on ~~NASDAQ~~NYSE MKT of our common stock on June ~~10, 2011,~~1, 2012, was ~~$14.14.~~$17.92. The following table sets forth the quarterly high and low sales prices of our common stock as reported on ~~NASDAQ~~NYSE MKT for the period from January ~~26,~~1, 2012 through March 31, 2012:

	High		Low

Fourth Quarter	$	26.70	$	15.47

The following table sets forth the quarterly high and low sales prices of our common stock as reported on NYSE MKT for the period from December 20, 2011 through ~~March~~December 31, 2011:

High Low
Fourth Quarter¹ $ 25.25 $ 13.56

	High		Low

Third Quarter¹	$	15.72	$	15.21

Our common stock commenced trading on ~~NASDAQ~~NYSE MKT (then NYSE Amex) on ~~January 26,~~December 20, 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.~~NYSE Amex. 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

		Year Ended March 31,
	2012				2011
		High		Low	High		Low

First Quarter¹	$	21.25	$	12.30	$	14.40	$	6.00
Second Quarter¹		15.60		10.60		13.00		9.20
Third Quarter¹׳²		16.60		10.77		24.00		9.00
Fourth Quarter³		N/A		N/A		25.25		13.50

	¹	Reported prices are from the OTCBB prior to January 26, 2011.
	²	Our common stock commenced trading on NASDAQ on January 26, 2011.
	³	Our common stock commenced trading on NYSE Amex on December 20, 2011. See tables above.

As of June ~~10, 2011,~~1, 2012, we had approximately ~~1,964~~1,945 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 and Equity Incentive Compensation Plan as of March 31, ~~2011.~~2012.

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~~holders¹

―

N/A

―

150,000

Equity compensation plans not approved by security holders²

N/A

15,115

~~Equity compensation plans not approved by security holders~~

―

~~N/A~~

―

Total

―

~~N/A~~

~~20,716~~

N/A

165,115

	¹	Equity Incentive Compensation Plan
	²	Director Compensation Plan

The 2011 Equity Incentive Compensation Plan (“the Equity Plan”) was adopted by the Board of Directors on July 27, 2011, subject to the approval of our Stockholders, which was obtained on September 23, 2011, making the Plan effective as of September 23, 2011. The Equity Plan was established to promote our interests and the interests of our Stockholders by encouraging the participants, namely employees, to increase their equity interest in us, thereby giving them an added incentive to work toward the Company’s continued growth and success, all the while enabling us to compete for the services of the individuals needed for our continued growth and success. Awards are in the form of restricted shares of common stock. These awards are subject to such restrictions as the Compensation Committee of the Board of Directors may impose, including vesting and risk of forfeiture.

The Equity Plan allows up to 150,000 shares of the Company’s common stock to be issued to personnel under the Plan. No shares were granted during the year ended March 31, 2012. However, 9,027 shares have been granted subsequent to March 31, 2012. Accordingly, as of June 1, 2012, 140,973 shares of common stock remain available for issuance under the Equity Plan.

The Board adopted a Director Compensation Plan ("(“the Director 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 Director 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 Director 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~~5,601 shares were granted during the year ended March 31, ~~2011,~~2012, for a total of ~~30,012~~35,613 shares that have been granted as of March 31, ~~2011.~~2012. Accordingly, as of the year ended March 31, ~~2011, 20,716~~2012, 15,115 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,~~2012, for each non-employee director was as follows: Robertson – ~~8,555~~6,272 shares; Rodgers – ~~8,555;~~6,272; and Calerich – ~~552.~~2,235.

In addition, on April 1, ~~2011,~~2012, each of the three non-employee directors was granted ~~1,867~~1,643 shares of restricted stock on April 1, ~~2011,~~2012, subject to vesting and forfeiture, resulting in ~~15,115~~10,185 shares of common stock remaining available for issuance under the Plan as of June ~~10, 2011.~~1, 2012. 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.

2219

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
2012:

¹	~~On October 22, 2008,~~	Total Number of Shares Purchased		Average Price Paid Per Share		Number of Shares Purchased as Part of a Publicly Announced Plan		Maximum Shares that May Yet be Purchased under 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 Plan

January 1, 2012 - January 31, 2012			-	$	-		-		103,284
February ~~10, 2010, the Board extended the termination date of the program from April 22, 2010 to October 22, 2011. During the year ended~~1, 2012 - February 28, 2012			-	$	-		-		103,284
March 1, 2012 - March 31, ~~2011, 10,997 shares were repurchased under the share buyback program and 109,440 shares remain available for future repurchase.~~2012			-	$	-		-		103,284

Total			-				-

ITEM 6

6. SELECTED FINANCIAL DATA

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

2320

ITEM 7

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~~2012 and ~~2010,~~2011, 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,~~2012, we had a working capital surplus of ~~$4,930,000~~$6,572,000 (a current ratio of ~~3.96:~~2.91:1) compared to a working capital surplus as of March 31, ~~2010~~2011 of ~~$5,062,000~~$4,930,000 (a current ratio of ~~3.53:~~3.96:1). The ~~increase~~decrease 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.

2421

Cash Flow. Cash provided by operating activities ~~decreased 2%~~doubled from ~~$2,666,000 for the year ended March 31, 2010 to~~ $2,624,000 for the year ended March 31, ~~2011.~~2011 to $5,278,000 for the year ended March 31, 2012. This change related primarily to the timing and collection of accounts receivable and the timing and payment of accounts payable and accrued ~~liabilities, and the application of prepaid balances.~~liabilities.

~~Net~~

Overall, net cash used in investing activities ~~more than doubled~~decreased 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~~$2,467,000 for the year ended March 31, ~~2011,~~2012. However, in 2012, investments in drilling and completion activities were significantly greater when compared to the prior year, but were partially offset by the sale of 38 wells in Colorado during the most recent fiscal year. During the year ended March 31, 2012, $7,687,000 was expended on anthe 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.~~acreage, as compared to $3,302,000 during the year ended March 31, 2011.

Net cash used in financing activities for the year ended March 31, 2012 was ~~nearly half of that of the pervious year.~~$84,000, utilized entirely for treasury share acquisition. During the year ended March 31, ~~2010, $208,000~~2011, $122,000 was used to purchase treasury ~~shares, while $122,000 was utilized for treasury share acquisition for the year ended March 31, 2011.~~shares. The Company’s share buyback program was adopted in October 2008 and will terminate in October ~~2011,~~2012, 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,~~2012, we spent ~~$2,729,000~~$8,757,000 on various projects. This compares to ~~$2,156,000~~$2,729,000 for the year ended March 31, ~~2010.~~2011. During the year ended March 31, ~~2011,~~2012, capital expenditures were comprised of ~~acquisitions~~drilling and completions of wells producing as of year end (47%), drilling of wells to be completed as of calendar year end (23%), converting unproductive wells to disposal wells (8%), leasehold (9%), and ~~completions (46%) and leasehold (7%~~acquisitions of producing properties (4%). ~~Approximately half~~The remaining 9% of costs were primarily dedicated to recompleting existing wells. The majority (87%) 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,~~2012, we have AFEs totaling ~~$588,000~~$5,574,000 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~~

On January 31, 2012, we completed the divestiture and sale of the Company’s working and/or override interests in 38 wells in Weld County, Colorado to an unrelated third party for $5,900,000. After customary adjustments and ~~plugged eight~~expenses, the net proceeds from the transaction were $5,404,000. The adjusted purchase price was impacted by commissions, sales costs and post effective date revenue and expense modifications to the purchase price. The wells ~~during~~were considered non-core properties for the ~~year ended March 31, 2011.~~

Company, given the Company’s focus on other areas, primarily the Williston Basin.

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~~2012 and ~~2010.~~2011. Certain prior year amounts may have been reclassified to conform to the current presentation.

	Year Ended March 31,				Year Ended March 31,
	2011		2010		2012		2011

Revenue
Oil	$	6,933,000	$	6,223,000	$	10,401,000	$	6,933,000
Gas		1,166,000		996,000		1,155,000		1,166,000
Total revenue2		8,099,000		7,219,000		11,556,000		8,099,000

Total production expense3		3,527,000		2,942,000		4,480,000		3,527,000

Gross profit	$	4,572,000	$	4,277,000	$	7,076,000	$	4,572,000

Depletion expense	$	1,131,000	$	1,185,000	$	1,065,000	$	1,131,000


Sales volume
Oil (Bbls)		93,613		98,865		108,653		93,613
Gas (Mcf) 1		172,386		228,575		226,760		172,386

Average sales price4
Oil (per Bbl)	$	74.06	$	62.94	$	95.73	$	74.06
Gas (per Mcf)	$	6.76	$	4.36	$	5.09	$	6.76

Average per BOE
Production expense3,4	$	28.83	$	21.48	$	30.59	$	28.83
Gross profit4	$	37.37	$	31.23	$	48.32	$	37.37
Depletion expense4	$	9.24	$	8.65	$	7.27	$	9.24

1	1	Due to the timing and accuracy of sales information received from a third party operator as described in “Volumes and Prices” ~~above,~~below, sales volume amounts may not be indicative of actual production or future performance.
2
	2	Amount does not include water service and disposal revenue. For the year ended March 31, ~~2011,~~2012, this revenue amount is net of ~~$107,000~~$156,000 in well service and water disposal revenue, which would otherwise total ~~$8,206,000~~$11,712,000 in revenue for the year ended March 31, ~~2011,~~2012, compared to ~~$50,000~~$107,000 to total ~~$7,269,000~~$8,206,000 for the year ended March 31, ~~2010.~~2011.
3
	3	Overall lifting cost (oil and gas production expenses and production taxes)
4
	4	Averages calculated based upon non-rounded figures

2723

The Year Ended March 31, ~~2011~~2012 Compared with the Year Ended March 31, ~~2010~~2011

Overview. Net income for the year ended March 31, ~~2011,~~2012, was ~~$1,602,000~~double that of the previous year at $3,279,000 compared to ~~net income of $1,028,000~~$1,602,000 for the year ended March 31, ~~2010, a 56% increase.~~2011. The increase in the sales ~~prices, as offset by a decline~~price per barrel of oil equivalent (“BOE”) and rise in sales volumes, ~~and increase~~offset by increases in production costs and general and administrative (“G&A”) expense, 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%~~$3,457,000 (43%) for the year ended March 31, ~~2011,~~2012, as compared to the year ended March 31, ~~2010, primarily~~2011, due to an overall 15% higher realized ~~oil~~price per BOE, and ~~gas prices per barrel of oil equivalent (“BOE”), as offset by reduced~~20% overall increase in sales volumes.

Volumes and Prices. On an equivalent barrel basis, sales ~~decreased 11% from 137,000~~were 146,000 BOE for the year ended March 31, ~~2010~~2012 compared to 122,000 BOE for the year ended March 31, 2011.

Oil sales volumes ~~decreased 5%~~increased 16% from ~~98,865 barrels for the year ended March 31, 2010 to~~ 93,613 barrels for the year ended March 31, 2011 to 108,653 barrels for the year ended March 31, 2012, while the average price per barrel increased ~~18%~~29% 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~~2011 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~~$95.73 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~~2012. The rise in oil ~~sales by approximately 4,731 barrels~~volumes resulted from production from the ~~year ended March 31, 2010. To a lesser extent, for the reasons detailed~~24 newly producing wells offset, expectedly, by declines 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.existing wells.

Natural gas sales volumes ~~decreased 24%~~increased 32% from ~~228,575 Mcf for the year ended March 31, 2010 to~~ 172,386 Mcf for the year ended March 31, 2011 to 226,760 Mcf for the year ended March 31, 2012, while the average price per Mcf ~~increased 55%~~dropped 25%, 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~~2011 to ~~the reporting~~$5.09 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.2012.

Production Expenses.

Production expenses are comprised of the following items:

	Year Ended March 31,				Year Ended March 31,
		2011		2010		2012		2011

Lease operating expenses	$	1,874,000	$	1,680,000	$	2,470,000	$	1,874,000
Workover costs		856,000		452,000
Production taxes		586,000		498,000		937,000		586,000
Workover expenses						789,000		856,000
Transportation and other expenses		211,000		312,000		284,000		211,000

	$	3,527,000	$	2,942,000	$	4,480,000	$	3,527,000

Oil and natural gas production expense increased ~~$585,000 (20%~~$953,000 (27%) for the year ended March 31, ~~2011,~~2012, as compared to the year ended March 31, ~~2010.~~2011. The two principal components of oil and gas production expense are routine lease operating expenses (“LOE”) 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~~

LOE, production taxes, and transportation and other expenses increased ~~$404,000 (89%~~$596,000 (32%), $351,000 (60%), and $73,000 (34%), respectively, for the year ended March 31, ~~2011,~~2012, 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 of2011. All fluctuate with sales revenue, which increased ~~$88,000 for the~~43% year ~~ended March 31, 2011, as compared to the year ended March 31, 2010.~~over year. Production taxes as a percent of oil and natural gas sales revenue ~~remained steady~~were comparable year over year at 7%8.1% versus 7.2%.

~~The increase in the production expenses as described above were offset by the $101,000 (32%~~ Workover expense decreased $67,000 (8%) ~~decrease in transportation costs~~ for the year ended March 31, ~~2011,~~2012, 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%~~6% from ~~$21.48 for the year ended March 31, 2010 to~~ $28.83 for the year ended March 31, ~~2011. The~~2011 to $30.59 for the year ended March 31, 2012. This increase ~~primarily related to this~~resulted from the increase ~~in workover costs as~~LOE 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%~~$49,000 (4%) for the year ended March 31, ~~2011,~~2012 as compared to the year ended March 31, ~~2010~~2011 due to the ~~reduction~~disposition of D-J Basin properties in ~~production.~~2012, somewhat offset by new wells. Depletion expense per BOE ~~increased~~decreased from ~~$8.65 for the year ended March 31, 2010 to~~ $9.24 for the year ended March 31, ~~2011.~~2011 to $7.27 for the year ended March 31, 2012.

General and administrative ("(“G~~&A"~~&A”) expense ~~decreased $264,000 (15%~~rose $561,000 (37%) for the year ended March 31, ~~2011,~~2012, as compared to the year ended March 31, ~~2010. This decrease was primarily due~~2011. Eighty percent of this increase relates to ~~reductions~~personnel costs, as additional management, staff and a Board member were added in ~~professional fees, which included investor relations~~2012. State franchise taxes resulted in 15% of the rise in costs. The sum of various other administrative costs ~~legal fees, accounting fees and Sarbanes-Oxley expenses.~~account for the remaining fluctuation in the expense. As a percent of total sales revenue, G&A expense ~~decreased from 24% for the year ended March 31, 2010 to~~remained steady at 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.both years.

Income ~~Taxes.~~Tax. For the year ended March 31, ~~2011,~~2012, we recorded income tax expense of ~~$206,000.~~$652,000. This amount consisted of a current period expense of ~~$104,000,~~$240,000, and deferred tax expense of ~~$102,000.~~$412,000. Our effective income tax rate ~~decreased~~increased from ~~12.57% for the year ended March 31, 2010 to~~ 11.41% for the year ended March 31, ~~2011.~~2011 to 16.59% for the year ended March 31, 2012. Our effective income tax rate was ~~lower~~higher for the year ended March 31, ~~2011,~~2012, primarily due to ~~an increase in deferred~~the tax ~~assets~~gain on the sale of the D-J Basin properties, offset by the utilization of greater percentage depletion as a result of recognizing the gain from the ~~amounts originally estimated on the prior year tax provision.~~these properties.

Critical Accounting Policies and Estimates

See Note 1 to the consolidated financial statements.

Recent Accounting Pronouncements

In December ~~2008,~~2011, the ~~SEC decreed modified instructions~~FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for ~~reporting oil and gas activities.~~all comparative periods presented. The ~~rule,~~Company is required to implement this guidance effective ~~and adopted~~ for the ~~Company’s year ended March 31, 2010, changes the oil~~first quarter of fiscal 2014 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~~expect the adoption of ~~this guidance, other than pricing, significantly impacted the~~ASU 2011-11 to have a material impact on its consolidated 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.statements.

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

7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

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

3026

ITEM 8

8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Earthstone Energy, Inc.

Table of Contents

Consolidated Financial Statements

and Accompanying Notes

March 31, ~~2011~~2012 and ~~2010~~2011

	Page

Report of Independent Registered Public Accounting Firm – Ehrhardt Keefe Steiner & Hottman PC		32
		28
Consolidated Balance Sheets		~~33-34~~
		29-30
Consolidated Statements of Operations		35
		31
Consolidated Statements of Shareholders’ Equity		36
		32
Consolidated Statements of Cash Flows		37
		33
Notes to Consolidated Financial Statements		~~38-51~~34-46

3127

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~~2012 and ~~2010,~~2011, 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~~2012 and ~~2010,~~2011, 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~~4, 2012

3228

Earthstone Energy, Inc.

Consolidated Balance Sheets

Page 1 of 2

	March 31,			March 31,			March 31,			March 31,
	2011			2010			2012			2011

Assets
Current assets:
Cash and cash equivalents	$	4,051,000		$	4,905,000		$	6,778,000		$	4,051,000
Accounts receivable:
Oil and gas sales		1,674,000			1,021,000			2,389,000			1,674,000
Joint interest and other receivables, net of allowance of $93,000 and $86,000, respectively		329,000			401,000
Joint interest and other receivables, net of allowance of $60,000 and $93,000, respectively								90,000			329,000
Other current assets		539,000			732,000			749,000			539,000

Total current assets		6,593,000			7,059,000			10,006,000			6,593,000

Oil and gas property, full cost method:
Proved property		35,379,000			33,915,000			37,112,000			35,379,000
Unproved property		3,112,000			1,555,000			4,409,000			3,112,000
Accumulated depletion and impairment		(24,713,000	)		(23,582,000	)		(25,778,000	)		(24,713,000	)

Net oil and gas property		13,778,000			11,888,000			15,743,000			13,778,000

Support equipment and other non-current assets, net of accumulated depreciation of $377,000 and $374,000, respectively		471,000			451,000
Support equipment and other non-current assets, net of accumulated depreciation of $383,000 and $377,000, respectively								457,000			471,000

Total non-current assets		14,249,000			12,339,000			16,200,000			14,249,000

Total assets	$	20,842,000		$	19,398,000		$	26,206,000		$	20,842,000

See accompanying notes to consolidated financial statements.

3329

Earthstone Energy, Inc.

Consolidated Balance Sheets

Page 2 of 2

	March 31,			March 31,			March 31,			March 31,
	2011			2010			2012			2011

Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	496,000		$	161,000		$	824,000		$	496,000
Accrued liabilities		1,167,000			1,836,000			2,610,000			1,167,000

Total current liabilities		1,663,000			1,997,000			3,434,000			1,663,000

Long-term liabilities:
Deferred tax liability		2,319,000			2,217,000			2,731,000			2,319,000
Asset retirement obligation		1,795,000			1,674,000
Asset retirement obligation, less current portion								1,693,000			1,795,000

Total long-term liabilities		4,114,000			3,891,000			4,424,000			4,114,000

Total liabilities		5,777,000			5,888,000			7,858,000			5,777,000

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
Common shares, $0.001 par value, 6,400,000 shares authorized and 1,788,000 and 1,782,000 shares issued, respectively								18,000			18,000
Additional paid-in capital		23,020,000			22,945,000			23,108,000			23,020,000
Treasury shares, at cost, 76,000 and 65,000 shares, respectively		(373,000	)		(251,000	)
Treasury shares, at cost, 82,000 and 76,000 shares, respectively								(457,000	)		(373,000	)
Accumulated deficit		(7,600,000	)		(9,202,000	)		(4,321,000	)		(7,600,000	)

Total shareholders’ equity		15,065,000			13,510,000			18,348,000			15,065,000

Total liabilities and shareholders’ equity	$	20,842,000		$	19,398,000		$	26,206,000		$	20,842,000

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

	March 31, 2012						March 31, 2011						March 31, 2010
	Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)
Proved reserves:
Balance, beginning of year		1,015,000			735,000			818,000			912,000			638,000			936,000
Revisions of previous estimates¹		38,000			8,000			167,000			(106,000	)		275,000			195,000
Extensions and discoveries²		295,000			351,000			62,000			39,000			4,000			10,000
Sales of reserves in place		(31,000	)		(221,000	)		—			—			—			—
Improved recovery		2,000			—			6,000			61,000			—			—
Purchase of reserves		17,000			—			55,000			1,000			—			—
Production³		(109,000	)		(227,000	)		(93,000	)		(172,000	)		(99,000	)		(229,000	)

Balance, end of year		1,227,000			646,000			1,015,000			735,000			818,000			912,000

Proved developed reserves:
Balance, beginning of year		1,015,000			735,000			727,000			912,000			587,000			907,000

Balance, end of year		1,077,000			515,000			1,015,000			735,000			727,000			912,000

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

Balance, end of year		150,000			131,000			—			—			91,000			—

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~~19 wells represent extensions and discoveries during the year ended March 31, 2012, all of which are located in North Dakota. Additions during the year ended March 31, 2011, inconsisted of eleven new wells – North Dakota (7), Montana (2), Colorado (1) and Texas (1). Additions during the year ended March 31, 2010, ~~consisted of~~pertained to 2 ~~new~~ wells drilled in Colorado and 1 ~~new~~ well drilled 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, 2012, 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

		For the Years Ended March 31,
		2012			2011			2010

Future cash inflows	$	116,925,000		$	81,053,000		$	55,991,000
Future cash outflows:
Production cost		(53,568,000	)		(41,185,000	)		(29,065,000	)
Development cost		(2,757,000	)		—			(991,000	)
Future income tax		(14,614,000	)		(6,545,000	)		(3,361,000	)

Future net cash flows		45,986,000			33,323,000			22,574,000
Adjustment to discount future annual net cash flows at 10%		(22,803,000	)		(15,826,000	)		(10,060,000	)

Standardized measure of discounted future net cash flows	$	23,183,000		$	17,497,000		$	12,514,000

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, 2012, 2011, ~~2010,~~ and ~~2009:~~2010:

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

		For the Years Ended March 31,
		2012			2011			2010

Standardized measure, beginning of year	$	17,497,000		$	12,514,000		$	7,199,000
Sales of oil and gas, net of production cost		(8,156,000	)		(5,204,000	)		(4,284,000	)
Net change in sales prices, net of production cost		5,135,000			5,886,000			6,279,000
Discoveries, extensions and improved recoveries, net of future development cost		10,285,000			1,567,000			154,000
Change in future development costs		—			—			467,000
Development costs incurred during the period that reduced future development cost		—			—			—
Sales of reserves in place		(1,761,000	)		—			—
Revisions of quantity estimates		916,000			3,806,000			5,280,000
Accretion of discount		2,113,000			1,874,000			720,000
Net change in income tax		(3,312,000	)		3,685,000			(1,582,000	)
Purchase of reserves		352,000			1,408,000			—
Changes in timing of rates of production		114,000			(8,039,000	)		(1,719,000	)

Standardized measure, end of year	$	23,183,000		$	17,497,000		$	12,514,000

5146

ITEM 9

9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A

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.~~2012. 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,~~2012, 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.~~2012.

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

9B. OTHER INFORMATION

None.

5347

Part III

ITEM 1010.

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 2012 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

Information relating to this item will be included in an amendment to this report or in the proxy statement for our ~~2011~~2012 annual shareholders’ meeting and is incorporated by reference in this report.

~~ITEM 11~~

~~EXECUTIVE COMPENSATION~~

~~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 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~~

5448

Part IV

~~Part IV~~

ITEM 1515.

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.

5549

3(ii)c		Amended and Restated Bylaws of Earthstone Energy, Inc., dated February 4, 2009, as amended on November 22, 2011, to add a new Section 2.13 to the Bylaws which indicates that the transfer books and records of the Company will not be closed for any purpose, incorporated by reference to Exhibit 3(ii)c of our Current Report on Form 8-K, filed with the SEC on November 23, 2011.
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., incorporated by reference to Exhibit 4.2 of our Annual Report on Form 10-K for the year ended March 31, 2011, filed ~~herewith.~~with the SEC on June 16, 2011..
10.1*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*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*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*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*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*10.7		Financial Consulting Agreement, effective March 16, 2011, between QAS, LLC and Earthstone, incorporated by reference to Exhibit 10.7 of our Annual Report on Form 10-K for the year ended March 31, 2011, filed ~~herewith.~~with the SEC on June 16, 2011.
10.8		2011 Equity Incentive Compensation Plan, effective September 23, 2011, incorporated by reference to Exhibit __ of Form DEF14A, filed with the SEC on July 29, 2011.
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)~~Officer), filed herewith.
31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial ~~Officer)~~Officer), filed herewith.
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)~~Officer), filed herewith.
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)~~Officer), filed herewith.
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.
101		The following materials from the Company’s quarterly report on Form 10-K for the year ended March 31, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Shareholders’ Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.

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

5650

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
		~~Date~~

By: /s/ Ray Singleton		June ~~15, 2011~~4, 2012

Ray Singleton, President and ~~Chief Executive Officer~~
Chief Executive Officer

By: /s/ Jim Poage		June ~~15, 2011~~4, 2012

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~~4, 2012

Ray Singleton, Director

By: /s/ Richard K. Rodgers		June ~~15, 2011~~4, 2012

Richard K. Rodgers, Director and
Compensation Committee Chairman

By: /s/ Monroe W. Robertson		June ~~15, 2011~~4, 2012

Monroe W. Robertson, Director and
Audit Committee Chairman

By: /s/ Andrew P. Calerich		June ~~15, 2011~~4, 2012

Andrew P. Calerich, Director

Delaware		84-0592823
(State of Incorporation or Organization)	~~84-0592823~~	(I.R.S. Employer Identification No.)

633 17th Street, Suite ~~1645~~1900 Denver, Colorado		80202-3619
(Address of principal executive office)	~~80202-3625~~	(Zip Code)

~~(303) 296-3076~~ ~~(Registrant’s telephone number, including area code)~~

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


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

		Year Ended						Year Ended
		March 31,						March 31,
		2011			2010			2012			2011

Revenues:
Oil and gas sales	$	8,099,000		$	7,219,000		$	11,556,000		$	8,099,000
Well service and water disposal revenue		107,000			50,000			156,000			107,000

Total revenues		8,206,000			7,269,000			11,712,000			8,206,000

Expenses:
Oil and gas production		2,941,000			2,444,000			3,543,000			2,941,000
Production tax		586,000			498,000			937,000			586,000
Well service and water disposal expenses		11,000			43,000			6,000			11,000
Depletion and depreciation		1,165,000			1,221,000			1,116,000			1,165,000
Accretion of asset retirement obligation		166,000			166,000			172,000			166,000
General and administrative		1,515,000			1,779,000			2,076,000			1,515,000

Total expenses		6,384,000			6,151,000			7,850,000			6,384,000

Income from operations		1,822,000			1,118,000			3,862,000			1,822,000

Other income (expense):
Interest and other income		12,000			90,000			75,000			12,000
Interest and other expenses		(26,000	)		(32,000	)		(6,000	)		(26,000	)

Total other income (expense)		(14,000	)		58,000			69,000			(14,000

Income before income taxes		1,808,000			1,176,000
Income before income tax								3,931,000			1,808,000

Current income tax expense		104,000			172,000			240,000			104,000
Deferred income tax expense (benefit)		102,000			(24,000	)
Deferred income tax expense								412,000			102,000

Total income tax expense		206,000			148,000			652,000			206,000

Net income	$	1,602,000		$	1,028,000		$	3,279,000		$	1,602,000

Per share amounts:
Basic	$	0.94		$	0.60		$	1.92		$	0.94
Diluted	$	0.94		$	0.60		$	1.92		$	0.94

Weighted average common shares outstanding:
Basic		1,710,453			1,707,353			1,709,178			1,710,453
Diluted		1,710,453			1,707,353			1,709,178			1,710,453

	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


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


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

	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

					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

	2012			2011
Valero Energy Company		20	%		19	%
Plains Marketing LP		11	%		4	%
Total		31	%		23	%

	2011	2010

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

		2012			2011

Asset retirement obligation, beginning of year	$	1,922,000		$	1,774,000
Liabilities settled		(401,000	)		(283,000	)
Liabilities incurred		133,000			49,000
Accretion		172,000			166,000
Revisions to estimates		-			216,000

Asset retirement obligation, end of year	$	1,826,000		$	1,922,000

Less current portion	$	(133,000	)	$	(127,000	)

Asset retirement obligation, less current portion	$	1,693,000		$	1,795,000

	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	%

	2012			2011

Federal tax at statutory rate	$	1,336,000		$	615,000
State taxes, net of federal benefit		68,000			26,000
Excess percentage depletion		(486,000	)		(270,000	)
Changes related to tax return amendments		(131,000	)		-
Changes in state rates and other adjustments to deferred tax assets		(135,000	)		(165,000	)

Income tax expense	$	652,000		$	206,000
Effective tax rate expressed as a percentage of income before income tax		16.6	%		11.4	%

	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	)

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

March 31, 2012									$	-	$	2,371,000	$	760,000	$	3,131,000
March 31, 2011	$	—	$	1,216,000	$	756,000	$	1,972,000		-		-		611,000		611,000
March 31, 2010		1,000		361,000		73,000		435,000
Prior Years		—		—		705,000		705,000		-		-		667,000		667,000

Total	$	1,000	$	1,577,000	$	1,534,000	$	3,112,000	$	-	$	2,371,000	$	2,038,000	$	4,409,000

		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