EARTHSTONE ENERGY INC - Annual Report: 2010 (Form 10-K)

e10k_3-10.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the Fiscal Year Ended March 31, 2010


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

Commission file number: 0-7914

(Exact Name of Registrant as Specified in its Charter)

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

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

Securities registered under Section 12(g) of the Act: Common Stock, $.001 par value

Common Stock, $.001 par value

Preferred Stock Purchase Rights

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

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No þ

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

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

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

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


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Registrant’s revenues for its most recent fiscal year: $7,269,000

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

As of June 18, 2010, 17,102,521 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from portions of the registrant’s definitive Proxy Statement for its 2010 Annual Meeting of Stockholders to be filed, pursuant to Regulation 14A, no later than 120 days after March 31, 2010.

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FORWARD-LOOKING STATEMENTS

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

• our strategies, either existing or anticipated;

• our future financial position, including anticipated liquidity, including the amount of and our ability to make debt service payments should

we utilize some or all of our available borrowing capacity;

• amounts and nature of future capital expenditures;

• acquisitions and other business opportunities;

• operating costs and other expenses;

• wells expected to be drilled, other anticipated exploration efforts and the expenses associated therewith;

• asset retirement obligations; and

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

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

• oil and natural gas prices;

• our ability to replace oil and natural gas reserves;

• loss of senior management or technical personnel;

• inaccuracy in reserve estimates and expected production rates;

• exploitation, development and exploration results;

• costs related to asset retirement obligations;

• a lack of available capital and financing;

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

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

• general economic, market or business conditions;

• factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment,

permitting issues, workovers, and weather;

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

• environmental liabilities;

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

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

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

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

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Earthstone Energy, Inc.

Form 10-K

March 31, 2010

Table of Contents

	Part I	Page

Item 1	Description of Business	4
Item 1A	Risk Factors	8
Item 1B	Unresolved Staff Comments	8
Item 2	Description of Property	8
Item 3	Legal Proceedings	13

	Part II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	14
Item 6	Selected Financial Data	16
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	23
Item 8	Financial Statements and Supplementary Data	24
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	44
Item 9A	Controls and Procedures	44
Item 9B	Other Information	44

	Part III

Item 10	Directors, Executive Officers and Corporate Governance	46
Item 11	Executive Compensation	46
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	46
Item 13	Certain Relationships and Related Transactions and Director Independence	46
Item 14	Principal Accountant Fees and Services	46

	Part IV

Item 15	Exhibits, Financial Statement Schedules	47
	Signatures	49

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Part I

ITEM 1

DESCRIPTION OF BUSINESS

Overview

Earthstone Energy, Inc. was incorporated in Delaware in 1969 as Basic Earth Science Systems, Inc. We changed our name in 2010 to Earthstone Energy, Inc. Earthstone Energy, Inc. (“Earthstone” or “the Company” or “we” or “our” or “us”) is an independent oil and gas exploration company primarily engaged in the exploration and development 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 focused in the North Dakota and Montana portions of the Williston basin, the Denver-Julesburg basin of Colorado, the southern portions of Texas, and along the on-shore portions of the Gulf Coast.

Strategy

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

The three components of our growth strategy are:

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

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

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

We continue to anticipate emphasizing the acquisition of producing properties over drilling in the coming year. While we will be drilling a considerable number of wells for our size (primarily to protect expiring leases and maintain our interests under existing acreage holdings), we are not expecting to acquire large, new, non-producing acreage positions in the coming year. We will also be focusing on keeping our operating costs under control as we expect rig and vendor service costs to rebound due to high demand. We caution that the following expectations may be altered by subsequent events or other, more attractive opportunities that may present themselves in the future.

Over the last two years, improvements in hydraulic stimulation technology have yielded significantly improved production rates in formations whose physical characteristics were once considered uneconomic. Previously unknown formations, such as the Marcellus, Haynesville, Eagle Ford, Bakken and recently the Niobrara, are now common names in the oil and gas industry. By virtue of the producing properties Earthstone has in Montana, North Dakota and Colorado, the Company has exposure to both the ongoing development of the Bakken formation in the Williston basin and now exposure to the new Niobrara play in Colorado.

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Areas of Focus

Williston Basin. The Williston basin continues to be our primary area of focus, both in terms of cash flow from existing properties and future expenditures. In the coming year, we intend to increase our efforts to acquire properties in the Williston basin while we continue to exploit ongoing drilling prospects. From a drilling perspective, we have several areas within the Williston basin where we expect drilling operations to continue during the current fiscal year. These areas are our on-going Banks prospect in McKenzie County, North Dakota, our Indian Hill acreage also in McKenzie County and our acreage in Divide County, North Dakota and Sheridan County, Montana.

Banks Field — McKenzie County, North Dakota. Earthstone retains a 6.5% working interest in approximately 13,000 gross (845 net) acres in the immediate vicinity of this field. To date, eight horizontal wells have been drilled; five in which the Company holds an interest. Both Panther Energy Company, LLC and Zenergy, Inc. have permitted wells on numerous spacing units which Earthstone, in-part, owns. While the Company expects future activity in this area in the upcoming year, we have not received any indication of when either company may commence additional drilling efforts.

Indian Hill Field — McKenzie County, North Dakota. The Company holds approximately 960 gross (192 net) acres in the Indian Hill Field. Several horizontal wells have been drilled within four miles of this acreage. With improving hydraulic stimulation technology, Earthstone anticipates that this acreage will be evaluated for horizontal Bakken development in the coming year.

Divide County, North Dakota — Sheridan County, Montana. Recently, several companies have drilled horizontal Bakken wells in these two counties. Little is known about the success of these efforts, especially on wells that have used newer hydraulic stimulation technology. However, leasing and leasehold prices are escalating in a manner similar to that seen earlier in areas that are now being aggressively drilled for Bakken production. By virtue of the producing properties Earthstone has in these two counties, along with undeveloped leasehold acreage, the Company has approximately 3,800 gross (2,400 net) acres which could be evaluated for horizontal Bakken development in the coming year.

Other Areas

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

Denver-Julesberg Basin — Weld County, Colorado. At March 31, 2009, Earthstone finished the first phase of our project to drill and complete sixteen new down-spaced wells on the Antenna Federal property in Weld County, Colorado. All development work on the first phase on this 640 acre section has been finalized. At March 31, 2010, we have begun our second and third phase of this project; to drill the “edge wells” around this section of land and to deepen some of the existing Codell wells to the J-Sand formation. For the six new “edge wells” the Company will hold a proportionately reduced interest due to having our acreage “pooled” with adjoining acreage. We expect to have a 1% to 26.25% revenue interest in Codell/Niobrara production from these wells. The working and revenue interest percentage for each individual well is different and is determined by the specific bottom-hole location of each respective well. On the third phase of this project, ten of the new Codell wells will be recompleted in the J-Sand formation. The Company expects to have a 13.125% to 52.5% revenue interest in J-Sand production. These respective interests are also determined by the specific bottom-hole location of each respective well and the spacing unit attributable to that well. In addition, in any given well, the respective working and revenue interests of the Codell/Niobrara production may be different when compared to the working and revenue J-Sand production. Kerr-McGee Oil & Gas Onshore, LP is the operator of the project.

In the past few months, word of successful horizontal Niobrara wells has created a frenzy of leasing activity in Colorado and Wyoming. Earthstone has rights to the Niobrara formation in Weld County, Colorado. Similar to our Codell formation interests, should horizontal Niobrara wells be drilled on this section, the working and revenue interest percentage for each individual well will be based on our proportionate interest in the specific spacing unit designated for that well.

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

Contemplated Activities

We are continually evaluating other drilling and acquisition opportunities for possible participation. The absence of news and/or press releases should not be interpreted as a lack of development or activity. Generally, at any one time, we are engaged in various stages of due diligence in connection with one or more drilling or acquisition opportunities. Unless required by applicable law, our policy is generally to not disclose the specifics of any such opportunity until such time as that transaction is finalized and we have entered into a definitive agreement regarding the same and then, only when such transaction is material to our business. Similarly, we do not speculate on the outcome of such ventures until the drilling, production or other results are available and have been verified by us.

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

Segment Information and Major Customers

Industry segment. We are engaged only in the upstream segment of the oil and gas industry, which comprises exploration, production, operations and development. We 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.

Markets. We are a small company and, as such, have no impact on the market for our goods and little control over the price received. Markets for 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 gas production is sold at prevailing wellhead gas prices, subject to additional charges customary to an area.

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

Major Customers. In the year ended March 31, 2010, approximately 43% of our oil and gas production revenues were received from sales to six purchasers. It is not expected that the loss of any one of these purchasers would cause a material adverse impact on our operations because alternative markets for our products are readily available. The remaining 57% of our revenue was received from non-operated properties where we have no control over the selection of the purchaser. On these properties our portion of the product is marketed on our behalf by the 21 different companies who operate these wells. These 21 companies may, unbeknownst to us, market to one or more of the same purchasers that we use. Therefore, we are unable to ascertain the total extent of combined purchaser concentration. To the extent of our knowledge, in the event of the bankruptcy of any one of our purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%. See also Note 1 – “Major Customers and Concentration of Credit Risk” in the Notes to Consolidated Financial Statements.

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Competition

The oil and gas industry is a highly competitive and speculative business. We encounter strong competition from major and independent oil companies in all phases of our operations. In this arena, we must compete with many companies having financial resources and technical staffs significantly larger than our own. Furthermore, having pursued an acquisition strategy for over a decade, we did not develop an in-house geologic or geophysical infrastructure, as have many of our competitors. Rather than incur the time and expense to develop in-house capability, we chose to enter joint ventures with other companies to accelerate our efforts. Competition is intense with respect to acquisitions and the purchase of large producing properties because of the limited capital resources available to us. As such, we have historically focused on smaller and/or marginal properties with behind-pipe potential in our acquisition efforts. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.

Employees

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

Regulations

General. Our operations are affected in varying degrees by federal, state, regional and local laws and regulations, including, but not limited to, laws governing well spacing, air emissions, water discharges, reporting requirements, endangered species, marketing, prices, taxes, allowable rates of production and the plugging and abandonment of wells, 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 made, and expect to make in the future, significant expenditures to comply with such laws and regulations. Changes to current local, state or federal laws and regulations in the jurisdictions where we operate could require additional capital expenditures and result in an increase in our costs. Although we are unable to predict what additional legislation, if any, might be proposed or enacted, additional regulatory requirements could impact the economics of our projects.

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

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ITEM 1A

RISK FACTORS

While we acknowledge that we have certain risk factors, smaller reporting companies are not required to provide information under this Item. Therefore, the absence of reporting under this Item should not be construed to indicate that we have no risk factors. Instead, we recognize that we have the same or similar risk factors as other comparable companies within our industry; especially companies with similar market capitalization and/or employee census.

ITEM 1B

UNRESOLVED STAFF COMMENTS

None.

ITEM 2

DESCRIPTION OF PROPERTY

Producing Properties: Location and Impact

At March 31, 2010, we owned a working interest in 101 producing oil wells and 39 producing gas wells in five states: North Dakota, Montana, Colorado, Texas and Wyoming. Virtually all of our property and production are pledged to secure any use of our bank line of credit. Refer to Credit Line under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for further information.

Productive Wells

	Gross Wells (1)				Net Wells (2)
	Oil		Gas		Oil		Gas

Colorado		—		37		—		7.50
Louisiana		1		1		0.01		0.10
Montana		20		—		9.77		—
North Dakota		56		—		9.64		—
Texas		23		1		20.66		0.11
Wyoming		1		—		0.47		—

Total		101		39		40.55		7.71

	(1)	The number of gross wells is the total number of wells in which a working interest is owned.

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

Production

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

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Reserves

At March 31, 2010, our estimated proved developed and undeveloped oil and gas reserves in barrels of oil equivalent (BOE) was 970,000, a 22.2% increase from the prior year’s estimated proved developed oil and gas reserves of 794,000 BOE. This increase was primarily caused by an increase in the 12 month average of the price of oil and gas on the first day of each month during fiscal 2010 when compared to the price on March 31 2009.

Geographically, our reserves are located in three primary areas: the Williston basin in North Dakota and Montana, the Denver-Julesburg (D-J) basin in Colorado and on-shore south Texas. The following table summarizes the estimated proved developed and undeveloped oil and gas reserves divided between operated and non-operated properties for these three areas as of March 31, 2010:

Estimated Proved Oil and Gas Reserves by Area

	Net Oil		Net Gas		BOE
	(Bbls)		(Mcf)		(1)		%

Williston Basin
Operated		202,000		45,000		210,000		21.6	%
Non-Operated		248,000		152,000		273,000		28.1	%

		450,000		197,000		483,000		49.7	%

South Texas/Onshore Gulf Coast
Operated		312,000		2,000		312,000		32.2	%
Non-Operated		―		126,000		21,000		2.2	%

		312,000		128,000		333,000		34.4	%

D-J Basin
Operated		16,000		310,000		68,000		7.0	%
Non-Operated		40,000		277,000		86,000		8.9	%

		56,000		587,000		154,000		15.9	%

Total		818,000		912,000		970,000		100	%

(1)

Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil)

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

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Preparation of Proved Reserves Estimates

Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance. Oil and gas reserves have been estimated as of March 31, 2010 for a significant portion of our properties by the Ryder Scott Company (“Ryder Scott”) of Houston, Texas. Ryder Scott estimated reserves for properties located in the states of Colorado, Louisiana, Montana, North Dakota and Texas comprising approximately 93% and 98% of the PV-10 of our oil and gas reserves as of March 31, 2010 and March 31, 2009, respectively. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. Ryder Scott has over eighty engineers and geoscientists on their permanent staff. Ryder Scott prepares our reserve estimate based upon a review of property interests being appraised, production from such properties, average annual costs of operation and development, commodity prices for production that comply with the new SEC guidelines and other engineering data/information we provide to them. This information is reviewed by knowledgeable members of our company, including our President and Chief Executive Officer, to ensure accuracy and completeness of the data prior to and after submission to Ryder Scott. The report of Ryder Scott dated May 3, 2010, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.3 to this report.

We concluded that it was not cost effective to have Ryder Scott prepare reserve estimates for 32 of our 91 properties because of their relatively low values. Instead, reserves for these properties were prepared by in-house personnel and contributed 7% and 2% of our reserves as of March 31, 2010 and March 31, 2009, respectively. In-house reserve estimates were prepared by Ray Singleton, President and Chief Executive Officer. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. In his capacity as an engineer, Mr. Singleton prepared reserve and economic estimates during his employment with both Amoco Production Company and Champlin Petroleum. Mr. Singleton continued providing economic evaluations for approximately 40 different clients through his engineering consulting firm, Singleton & Associates, from 1982 to 1988, and thereafter for Earthstone Energy, Inc. since his employment in 1988. In addition, Mr. Singleton is currently a member of the Society of Petroleum Engineers.

Technologies Used in Preparation of Proved Reserves Estimates

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

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

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

Estimated Proved Developed and Undeveloped Oil and Gas Reserves

Proved

Developed

Producing

Non-Producing

Undeveloped

Total Proved (1)

Net Remaining Reserves

Oil/Condensate - Bbls

727,000

―

91,000

818,000

Plant Products - Bbls

―

Gas - MCF

912,000

―

912,000

(1)

Disclosure of probable and possible reserves became optional under SEC guidelines for years ended March 31, 2010, and accordingly, we have elected not to present probable or possible reserves.

The process of estimating oil and gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Annual Report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

Proved Undeveloped Reserves

At March 31, 2010, we had 91,000 barrels of proved undeveloped reserves, which will require future capital expenditures of approximately $991,000 to develop. At March 31, 2009 we had one proved undeveloped property. During fiscal 2010 this property was re-classified to the proved and developed category. Approximately $490,000 was spent in this development effort. None of the proved undeveloped reserves at March 31, 2010 have been on our reserve report for more than five years.

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Oil and Gas Production and Sales Prices

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

Drilling Activities

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

Exploratory and Developmental Wells Drilled

2010

2009

2008

Gross

Net

Gross

Net

Gross

Net

Exploratory (1)

Productive

Oil

―

0.01

―

Gas

―

Dry holes

0.55

―

Total

0.55

0.01

―

Development (2)

Productive

Oil

0.36

0.09

―

Gas

―

2.27

1.60

Dry holes

―

Total

0.36

2.36

1.60

(1)

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

(2)

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

Leasehold Acreage

We lease the rights to explore for and produce oil and gas from mineral owners. Leases (quantified in acres) expire after their primary term unless oil or gas production is established. Prior to establishing production, leases are generally considered undeveloped. After production is established, leases are considered developed or “held-by-production.” Our acreage is comprised of developed and undeveloped acreage as follows:

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Gross and Net Acreage

	Developed Acreage				Undeveloped Acreage (1)
	Gross (2)		Net (3)		Gross (2)		Net (3)

Colorado		640		384		—		—
Louisiana		687		51		—		—
Montana		6,490		3,206		2,761		2,123
North Dakota		14,856		2,952		26,506		4,623
Texas		3,080		2,486		—		—
Utah		—		—		35,945		719
Wyoming		1,555		329		40		1

Total		27,308		9,408		65,252		7,466

	(1)	Undeveloped acreage encompasses leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas.
	(2)	The number of gross acres is the total number of acres in which a working interest is owned.
	(3)	A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Field Service Equipment

At March 31, 2010, our remaining active subsidiary, Basic Petroleum Services, Inc. located in Bruni, Texas, owned a trailer house/field office, a shallow pulling rig, a large winch truck, a skid-mounted cementing unit, four pickup trucks and various ancillary service vehicles. None of the vehicles are encumbered.

Office Lease

We currently lease approximately 4,000 square feet of office space in downtown Denver, Colorado from an independent third party for approximately $5,853 per month escalating at a rate of approximately $170 at the end of each year. The lease term is for a five-year period ending April 30, 2013. For additional information see Note 7 to the Consolidated Financial Statements.

ITEM 3

LEGAL PROCEEDINGS

None.

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Part II

ITEM 5

MARKET FOR REGISTRANT’S COMMON EQUITY,

RELATED STOCKHOLDER MATTERS

AND ISSUER PURCHASES OF EQUITY SECURITIES

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

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

The following table sets forth the range of high and low bid quotations for our common stock for each of the periods indicated below as reported by the OTCBB. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions. The closing bid price on June 18, 2010 was $1.30.

	High		Low

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

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

As of June 18, 2010, we had approximately 3,919 shareholders of record. We have never paid a cash dividend on our common stock. Our loan agreement has a covenant prohibiting the payment of dividends to stockholders without our lender’s prior written consent. Any future dividend on common stock will be at the discretion of the Board of Directors and will be dependent upon the Company’s earnings and financial condition, receipt of our lender’s consent and other factors. Our Board of Directors presently has no plans to pay any dividends in the foreseeable future.

Unregistered Sales of Equity Securities

Not applicable.

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Securities Authorized For Issuance under Equity Compensation Plans

The following table contains information with respect to our Director Compensation Plan as of the end of our fiscal year ended March 31, 2010.

Equity Compensation Plan Information

Plan Category

Number of securities to be issued upon exercise of outstanding options, warrants and rights

Weighted-average exercise price of outstanding options, warrants and rights

Number of securities remaining available for future issuance under equity compensation plans

Equity compensation plans approved by security holders

―

N/A

―

Equity compensation plans not approved by security holders

―

N/A

300,000

Total

―

N/A

300,000

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

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

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Purchases of Equity Securities

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

	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Number of Shares Purchased as Part of a Publicly Announced Plan (1)		Maximum Shares that May Yet be Purchased under the Plan (1)

January 1, 2010 - January 31, 2010		9,415	$	0.84		9,415		1,207,570
February 1, 2010 - February 28, 2010		400	$	0.80		400		1,207,170
March 1, 2010 - March 31, 2010		2,800	$	0.85		2,800		1,204,370

Total		12,615				12,615

(1)

On October 22, 2008, the Company’s Board of Directors authorized a stock buyback program for the Company to repurchase up to 500,000 shares of its common stock 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 1,500,000. On February 10, 2010, the board extended the termination date of the program from April 22, 2010 to October 22, 2011. During the year ended March 31, 2010, 265,430 shares were repurchased under the stock buyback program and 1,204,370 shares remain available for future repurchase.

ITEM 6

SELECTED FINANCIAL DATA

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

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ITEM 7

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Liquidity Outlook

Our primary source of funding is the net cash flow from the sale of our oil and gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and then sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. Assuming oil prices do not decline significantly from current levels, we believe the cash generated from operations will provide sufficient working capital for us to meet our existing and normal recurring obligations as they become due. In addition, as mentioned in the “Debt” section below, we have an available borrowing capacity of $4,000,000 as of June 18, 2010.

Capital Structure and Liquidity

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

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

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

Under the credit facility, we must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. The loan agreement has covenants requiring us to maintain a debt-to-equity ratio of less than one and a current ratio of at least 1:1 inclusive of unused borrowing capacity and exclusive of the current portion of long-term debt. We were in compliance with all covenants at March 31, 2010.

During the years ended March 31, 2010 and 2009, we utilized none of our credit facility. Our effective annual interest rate is 6.50% or prime plus 0.25%, whichever is greater. On June 18, 2010 we had no outstanding principal balance on the line of credit, with the entire $4,000,000 available for borrowing. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities. See Note 6 to the Consolidated Financial Statements for a more detailed discussion of our bank credit facility.

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Hedging. During 2010 and 2009, we did not participate in any hedging activities, nor did we have any open futures or option contracts. Additional information concerning our hedging activities appears in Note 1 to the Consolidated Financial Statements.

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

Cash Flow. As mentioned above, our primary source of funding is the cash flow from our operations. Cash provided by operating activities decreased 7.2% from $2,872,000 in 2009 to $2,666,000 in 2010. Net cash used in investing activities decreased 62.2% from $4,338,000 in 2009 to $1,641,000 in 2010, which relates primarily to our drilling and completion activities during the year.

We have not borrowed on our line of credit since June 2006. Cash used in financing activities was $17,000 in 2009 for the purchase of treasury shares net of proceeds from the exercise of the remaining stock options outstanding, while cash used in financing activities was $208,000 in 2010 for the purchase of treasury shares.

Capital Expenditures. During 2010 our capital expenditures were primarily focused on properties in the Williston Basin of Montana and North Dakota. On an accrual basis, total capital expenditures during 2010 for oil and gas property and equipment and various leasehold interests were $2,156,000. Of these expenditures, $1,887,000 (87.5%) is attributable to the Williston Basin for the drilling, completion and leasehold costs of wells in this area. These projects were funded entirely with internally generated cash flow. See also the Areas of Focus and Company Developments sections of Part 1 of this report for further discussion related to our exploration and development activities.

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

Divestitures/Abandonments. We plugged two wells during 2010 and incurred some additional costs pertaining to the abandonment of wells that are in the process of being plugged.

Impact of Inflation. We deal primarily in US dollars. Inflation has not had a material impact on the Company in recent years because of the relatively low rates of inflation in the United States.

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

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Results of Operations

Selected Financial Information

The following table shows selected financial information and averages for each of the three prior years in the period ended March 31.

	Years Ended
	March 31,
	2010		2009		2008

Sales volume
Oil (barrels)		98,865		92,657		89,400
Gas (mcf) 1		228,575		175,413		108,600

Revenue
Oil	$	6,223,000	$	7,406,000	$	6,748,000
Gas		996,000		1,585,000		667,000
Total revenue 2		7,219,000		8,991,000		7,415,000

Total production expense 3		2,935,000		3,183,000		2,706,000

Gross profit	$	4,284,000	$	5,808,000	$	4,709,000

Depletion expense	$	1,185,000	$	1,188,000	$	673,000

Average sales price 4
Oil (per barrel)	$	62.94	$	79.93	$	75.47
Gas (per mcf)	$	4.36	$	9.04	$	6.13

Average per BOE
Production expense 3,4,5	$	21.43	$	26.09	$	19.27
Gross profit 4,5	$	31.28	$	47.61	$	43.96
Depletion expense 4,5	$	8.65	$	9.74	$	5.59

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

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Fiscal 2010 Compared with Fiscal 2009

Overview. Net income for the year ended March 31, 2010 was $1,028,000 compared to net income of $578,000 for the year ended March 31, 2009, a 77.9% increase. This increase is more a function of depressed income in 2009 rather than results in 2010. Net income in 2009 was adversely impacted by a sizeable impairment expense due to a significant decline in oil and gas prices during the third quarter of 2009. With rising prices in 2010, a similar expense was not incurred in the current year. While oil and gas sales volume increased in 2010, these increases were partially offset by decreased average commodity prices when compared to 2009. While overall production expenses decreased during 2010, general and administrative increased.

Revenues. Oil and gas sales revenue decreased $1,772,000 (19.7%) in 2010 over 2009 as a result of overall lower average oil and gas prices despite increased oil and gas production. Oil sales revenue decreased $1,183,000 (16.0%) and Gas sales revenue decreased $589,000 (37.2%) in 2010 from 2009.

Volumes and Prices. Oil sales volumes increased 6.7% from 92,657 barrels in 2009 to 98,865 barrels in 2010, while the average price per barrel decreased 21.2% from $79.93 in 2009 to $62.94 in 2010. Gas sales volume increased 30.3% from 175.4 million cubic feet (MMcf) in 2009 to 228.6 MMcf in 2010. The average price per Mcf decreased 51.8%, from $9.04 in 2009 to $4.36 in 2010. The production increase in gas in 2010 was primarily due to adjustments made during the year, to our revenues, sales volumes, sales prices and severance taxes following the receipt of higher production and sales volume information related to the Antenna Federal property in Weld County, Colorado. Most of the Company’s gas sales are from our non-operated interest in the Antenna Federal property in Weld County, Colorado. During the prior year, the Company had estimated gas sales on this property based on the information available at the time and the Company’s experience in the area. During 2010, we received actual sales volumes and related information from the operator, which were significantly higher than the sales volumes and related information previously reported to, and accrued by, the Company in the prior year. The incorporation of this information resulted in higher sales volumes, sales prices and severance taxes for the current year. Due to the adjustments made during 2010, for updated sales volumes and related information received from the operator of the Antenna Federal property, the higher sales volumes for 2010, are not representative of actual sales volume for this year and should not be used to predict future production or sales volumes. In addition, production taxes as a percentage of sales, general and administrative expenses as a percentage of sales and any metric whose denominator is related to sales volumes is likely understated. On an equivalent barrel (BOE) basis, sales increased 12.3% from 122,000 BOE in 2009 to 136,961 BOE in 2010.

Expenses. Oil and gas production expense decreased $102,000 (4.0%) in 2010 over 2009. Oil and gas production expense is comprised of two components: routine lease operating expenses and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal and minor surface equipment repairs. Workovers primarily include downhole repairs and are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their associated costs can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas production expense from period to period.

Routine lease operating expense increased $16,000 (0.8%) from $1,969,000 in 2009 to $1,985,000 in 2010, which is relatively comparable. Workover expense decreased $118,000 (20.7%) from $570,000 in 2009 to $452,000 in 2010 related to an overall decrease in workovers of various wells primarily located in the Williston basin of Montana and North Dakota. On an equivalent barrel basis, routine lease operating expense decreased 10.2% from $16.14 per BOE in 2009 to $14.49 in 2010, while workover expense decreased 29.4% from $4.67 in 2009 to $3.30 per BOE in 2010.

Production taxes, which are a function of sales revenue, decreased $146,000 (22.7%) in 2010 from 2009. Production taxes as a percent of oil and gas sales revenue decreased from 7.1% in 2009 to 6.9% in 2010.

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The overall lifting cost (oil and gas production expense plus production taxes) per BOE was $21.43 in 2010 compared to $26.09 in 2009. The decrease primarily related to the decrease in production taxes as described in the preceding paragraph. This lifting cost per equivalent barrel is not indicative of all wells, and certain high cost wells could be shut in should oil prices drop below certain levels.

Depreciation and depletion expense decreased $3,000 (0.2%) in 2010 from 2009. Depreciation and depletion expense per BOE decreased from $10.03 in 2009 to $8.91 in 2010.

Accretion of asset retirement obligation increased $68,000 (69.4%) in 2010 from 2009. This increase is a result of new well additions during the year and revisions to the estimated lives of some of our wells sharing the same leased acreage. Additional information concerning asset retirement obligations and related activity during 2010 can be found in Note 5 to the Consolidated Financial Statements.

Impairment of oil and gas properties occurred during the prior year as a result of the decline in oil and gas prices. Like a number of companies in our industry, we incurred a charge consistent with the results of our “ceiling test” which places a “ceiling” on our capitalized costs, thereby limiting our pooled capital costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds this “ceiling,” we are required to record a write-down to the extent of such excess. This write-down is a non-cash charge to earnings. It reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. Accordingly, during the year ended March 31, 2009, we determined that our capitalized costs exceeded the ceiling test limit and recorded an impairment write-down of $2,694,000, compared to no ceiling test impairment for the year ended March 31, 2010.

General and administrative (G&A) expense increased $432,000 (32.1%) in 2010 over 2009. This increase was primarily due to consulting fees in connection with investor relations and SEC reporting requirements, legal fees and related proxy and shareholder expenses and increased executive compensation. The percentage of G&A expense that was billed out to operated properties was 11.7% in 2010 compared to 14.4% in 2009. G&A expense per BOE increased 17.6% from $11.04 in 2009 to $12.99 in 2010. G&A expense as a percentage of total sales revenue also increased from 14.8% in 2009 to 24.5% in 2010.

Other Income/Expense. Interest and other income increased from $57,000 in 2009 to $90,000 in 2010 due to increases in miscellaneous items. Interest and other expenses decreased from $34,000 in 2009 to $32,000 in 2010.

Income Taxes. In 2010, we recorded income tax expense of $148,000 comprised of a current year income tax provision of $172,000, and a deferred income tax benefit of $24,000. This compares to a 2009 income tax benefit of $212,000. At March 31, 2009, we had a net deferred tax benefit of $(558,000). Our effective income tax rate increased from (56.34)% for 2009 to 12.57% for 2010. Our effective income tax rate was lower for 2009 primarily due to an increase in estimated deductions for statutory depletion and impairment expense.

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Critical Accounting Policies and Estimates

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

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

Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of our oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves attributable to these properties. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Ninety-three percent of our reported oil and gas reserves at March 31, 2010 are based on estimates prepared by an independent petroleum engineering firm. The remaining seven percent of our oil and gas reserves were prepared in-house. See also Note 12 to the Consolidated Financial Statements.

Asset Retirement Obligations. We have significant obligations related to the plugging and abandonment of our oil and gas wells, the removal of equipment and facilities and returning the land to its original condition. As we account for asset retirement obligations we are required to estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash expenditures and inflation rates. The nature of these estimates requires management to make judgments based on historical experience and future expectations related to timing. We review the estimate of our future asset retirement obligations quarterly. These quarterly reviews may require revisions to these estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. See also Note 5 to the Consolidated Financial Statements.

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Off Balance Sheet Arrangements

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

Recent Accounting Pronouncements

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

ITEM 7A

QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

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

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ITEM 8

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Earthstone Energy, Inc.

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Consolidated Financial Statements

and Accompanying Notes

March 31, 2010 and 2009

	Page
Report of Independent Registered Public Accounting Firm – Ehrhardt Keefe Steiner & Hottman PC	25
Consolidated Balance Sheets	26-27
Consolidated Statements of Operations	28
Consolidated Statements of Shareholders’ Equity	29
Consolidated Statements of Cash Flows	30
Notes to Consolidated Financial Statements	31-43

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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, 2010 and 2009, and the related statements of operations, shareholders’ equity, and cash flows for the years ended March 31, 2010 and 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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 audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Earthstone Energy, Inc. as of March 31, 2010 and 2009, and the results of their operations and their cash flows for the years ended March 31, 2010 and 2009 in conformity with accounting principles generally accepted in the United States of America.

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

Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado

June 18, 2010

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Earthstone Energy, Inc.

Consolidated Balance Sheets

	March 31,			March 31,
	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	4,905,000		$	4,088,000
Accounts receivable:
Oil and gas sales		1,021,000			1,611,000
Joint interest and other receivables, net of $86,000 and $71,000 in allowance for bad debt, respectively		401,000			230,000
Other current assets		732,000			508,000

Total current assets		7,059,000			6,437,000

Oil and gas property, full cost method:
Proved property		33,915,000			32,187,000
Unproved property		1,555,000			1,077,000
Accumulated depletion and impairment		(23,582,000	)		(22,397,000	)

Net oil and gas property		11,888,000			10,867,000

Support equipment and other non-current assets, net of $374,000 and $337,000 in accumulated depreciation, respectively		451,000			458,000

Total non-current assets		12,339,000			11,325,000

Total assets	$	19,398,000		$	17,762,000

See accompanying notes to consolidated financial statements.

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Earthstone Energy, Inc.

Consolidated Balance Sheets

	March 31,			March 31,
	2010			2009
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	161,000		$	64,000
Accrued liabilities		1,836,000			1,328,000

Total current liabilities		1,997,000			1,392,000

Long-term liabilities:
Deferred tax liability		2,217,000			2,242,000
Asset retirement obligation		1,674,000			1,558,000

Total long-term liabilities		3,891,000			3,800,000

Total liabilities		5,888,000			5,192,000

Commitments

Shareholders’ Equity:
Preferred stock, $.001 par value, 3,000,000 authorized and none issued or outstanding		—			—
Common stock, $.001 par value, 32,000,000 shares authorized and 17,704,000 and 17,506,000 shares issued and outstanding, respectively		18,000			18,000
Additional paid-in capital		22,945,000			22,825,000
Treasury stock (646,000 and 380,000 shares respectively) at cost		(251,000	)		(43,000	)
Accumulated deficit		(9,202,000	)		(10,230,000	)

Total shareholders’ equity		13,510,000			12,570,000

Total liabilities and shareholders’ equity	$	19,398,000		$	17,762,000

See accompanying notes to consolidated financial statements.

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Earthstone Energy, Inc.

Consolidated Statements of Operations

		Year Ended
		March 31,
		2010		2009

Revenues:
Oil and gas sales	$	7,219,000	$	8,991,000
Well service and water disposal revenue		50,000		95,000

Total revenues		7,269,000		9,086,000

Expenses:
Oil and gas production		2,437,000		2,539,000
Production tax		498,000		644,000
Well servicing expenses		43,000		33,000
Depreciation and depletion		1,221,000		1,224,000
Accretion of asset retirement obligation		166,000		98,000
Asset retirement expense		7,000		164,000
Impairment of oil and gas properties		―		2,694,000
General and administrative		1,779,000		1,347,000

Total expenses		6,151,000		8,743,000

Income from operations		1,118,000		343,000

Other Income (Expense):
Interest and other income		90,000		57,000
Interest and other expenses		(32,000)		(34,000)

Total other income		58,000		23,000

Income before income taxes		1,176,000		366,000

Current income tax expense		172,000		346,000
Deferred income taxes (benefit)		(24,000)		(558,000)

Total income tax expense (benefit)		148,000		(212,000)

Net income	$	1,028,000	$	578,000

Per share amounts:
Basic	$	0.06	$	0.03
Diluted	$	0.06	$	0.03

Weighted average common shares outstanding:
Basic		17,073,526		17,105,352
Diluted		17,073,526		17,105,352

See accompanying notes to consolidated financial statements.

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Earthstone Energy, Inc.

Consolidated Statements of Shareholders’ Equity

Years Ended March 31, 2010 and 2009

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

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

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

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

Purchase of treasury shares		—		—		—		(266,000)		(208,000)		—		(208,000)
Shares issued to independent directors		192,000		—		120,000		—		—		—		120,000
Shares issued to employees		6,000		—		—		—		—		—		—
Net income		—		—		—		—		—		1,028,000		1,028,000

March 31, 2010		17,704,000	$	18,000	$	22,945,000		(646,000)	$	(251,000)	$	(9,202,000)	$	13,510,000

See accompanying notes to consolidated financial statements.

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Earthstone Energy, Inc.

Consolidated Statements of Cash Flows

		Year Ended
		March 31,
		2010		2009

Cash flows from operating activities:
Net income	$	1,028,000	$	578,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		1,221,000		1,224,000
Deferred tax liability		(24,000)		(558,000)
Accretion of asset retirement obligation		166,000		98,000
Share based compensation		72,000		24,000
Impairment of oil and gas properties		―		2,694,000
Change in:
Accounts receivable, net		419,000		(495,000)
Other assets		(224,000)		(287,000)
Accounts payable and accrued liabilities		8,000		(406,000)

Net cash provided by operating activities		2,666,000		2,872,000

Cash flows from investing activities:
Oil and gas property		(1,612,000)		(4,338,000)
Support equipment		(29,000)		―

Net cash used in investing activities		(1,641,000)		(4,338,000)

Cash flows from financing activities:
Proceeds from exercise of common stock options		―		3,000
Purchase of treasury shares		(208,000)		(20,000)

Net cash used in financing activities		(208,000)		(17,000)

Cash and cash equivalents:
Increase (decrease) in cash and cash equivalents		817,000		(1,483,000)
Balance, beginning of year		4,088,000		5,571,000

Balance, end of period	$	4,905,000	$	4,088,000

Supplemental disclosure of cash flow information:
Cash paid for interest	$	17,000	$	10,000
Cash paid for income tax	$	6,500	$	517,000
Non-cash:
Increase in oil and gas property due to asset retirement obligation	$	54,000	$	33,000
Vested shares issued as compensation	$	48,000	$	24,000
Additions to oil and gas also included in accrued liabilities	$	687,000	$	43,000

See accompanying notes to consolidated financial statements.

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Earthstone Energy, Inc.

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Organization and Nature of Operations. Earthstone Energy, Inc. (“Earthstone” or “the Company” or “we” or “our” or “us”), was originally organized in July 1969 as Basic Earth Science Systems, Inc. We changed our name in 2010 to Earthstone Energy, Inc. We are principally engaged in the acquisition, exploitation, development, operation and production of crude oil and natural gas. Our primary areas of operation are the Williston basin in North Dakota and Montana, south Texas and the Denver-Julesburg basin in Colorado.

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

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

Oil and Gas Properties. We follow the full cost method of accounting for our oil and gas activity. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized, with the exception of unproved properties which are periodically reviewed for impairment by reviewing the status of the activity on those properties and surrounding properties either held by us or other parties. Capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves using the 12 month average price of oil and gas on the first day of each month and costs discounted at 10 percent plus the lower of cost or fair value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. While we did not incur a ceiling limitation charge for the year ended March 31, 2010, we incurred a ceiling test limitation charge in the amount of $2,694,000 during the year ended March 31, 2009, representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules.

All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties we own. Depletion expense per equivalent barrel of production was $8.65 and $9.74 for 2010 and 2009, respectively.

Income Taxes. We account for income taxes in accordance with FASB issued authoritative guidance which requires the use of the “liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial statement and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. For further information, see Note 9 below.

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Earnings Per Share. Our earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of securities, if any, that could share in the earnings of the Company and is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options. The following is a reconciliation of basic and diluted earnings per share for the years ended March 31, 2010 and 2009:

		2010		2009
Numerator:
Net income available to common shareholders	$	1,028,000	$	578,000

Denominator:
Denominator for basic earnings per share		17,073,526		17,105,352
Effect of dilutive securities:
Stock options		—		—

Denominator for diluted earnings per share		17,073,526		17,105,352

There were no options issued or outstanding for 2010 or 2009. See Note 8 below for further discussion of our stock options.

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

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

Hedging Activities. We had no hedging activities in 2010 and 2009. Hedging strategies, or absence of hedging, may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events which we are not able to anticipate.

Support Equipment and Other. Support equipment (including such items as vehicles, office furniture and equipment and well servicing equipment) is stated at cost. Depreciation of support equipment and other property is computed using primarily the straight-line method over periods ranging from five to seven years.

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

Long-Term Assets. We apply FASB issued authoritative guidance to long-lived assets not included in oil and gas properties. Under the guidance, all long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. An impairment loss is recognized when the carrying value of a long-lived asset is not recoverable and exceeds its fair value.

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Major Customers and Concentration of Credit Risk. Purchasers of 10% or more of our oil and gas production revenue received at March 31, 2010 and 2009 are as follows:

	2010	2009

Valero Energy	16%	17%
Nexen Marketing USA, Inc.	10%	14%
Murphy Oil USA, Inc.	8%	25%
Plains Inc.	—	14%

Total	34%	70%

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

In the year ended March 31, 2010, approximately 57% of our oil and gas revenue was received from non-operated properties where we have no control over the selection of the purchaser. On these properties our portion of the product was marketed on our behalf by the 21 different companies who operate these wells. These 21 companies may, unbeknownst to us, market to one or more of the same purchasers that we use. Therefore, we are unable to ascertain the total extent of combined purchaser concentration. To the extent of our knowledge, in the event of the bankruptcy of any one of our purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%.

Stock Option Plan. We are required to recognize all equity-based compensation, including stock option grants, as stock-based compensation expense in our Consolidated Statements of Operations based on the fair value of the compensation. No options have been granted since July 2003, and the plan expired in July 2005. Therefore, we issued no further stock options in either 2010 or 2009. See Note 8 below for further discussion of the Company’s stock options.

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

Reclassifications. Certain prior year amounts were reclassified to conform to current year presentation. Such reclassifications had no effect on the prior year net income.

Recent Accounting Pronouncements

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

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

On April 29, 2009, the FASB issued guidance related to financial instruments, which requires publicly-traded companies to provide disclosures on the fair value of financial instruments in interim financial statements, and is effective for interim periods ended after June 15, 2009. We have adopted these new provisions, which did not have a material impact on the Company’s consolidated financial statements or results of operations.

On April 1, 2009, the FASB issued guidance related to business combinations, which addresses application issues associated with initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination, including the treatment of contingent consideration, acquisition costs, research and development assets and restructuring costs. In addition, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. The new guidance is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will apply the new provisions to future acquisitions.

In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements is a broader definition of reserves, which allows reporting of probable and possible reserves, in addition to consideration of new technologies and non-traditional resources. In addition, oil and gas reserves will be reported using an average price based on the first-day-of-the-month price during the prior 12-month period, rather than year-end prices. The new rules are effective for years ending on or after December 31, 2009. The adoption of the new rules is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or financial statements which also impact the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new guidance, subsequent price increases cannot be considered in the ceiling test calculation. The Company does not believe that it is practicable to estimate the effect of applying the new rules on net loss or the amounts recorded for depreciation, depletion and amortization and ceiling impairment for the year ended March 31, 2010.

In September 2006, the FASB issued guidance related to fair value measurements and disclosures, which defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. The new guidance is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB proposed a one year deferral of the implementation for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On April 1, 2008, we adopted the new guidance with the one-year deferral for non-financial assets and liabilities. The adoption of the new guidance did not have a material impact on our financial position, results of operations or cash flows. Beginning April 1, 2009, we have adopted the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The adoption did not have a material impact on our financial statements.

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2. Other Current Assets

Other current assets at March 31, 2010 and 2009 consisted of the following:

		2010		2009

Lease and well equipment inventory	$	399,000	$	170,000
Drilling and completion cost prepayments		244,000		149,000
Prepaid insurance premiums		49,000		44,000
Other current assets		40,000		145,000

Total other current assets	$	732,000	$	508,000

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

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

3. Other Non-Current Assets

Other non-current assets at March 31, 2010 and 2009 consisted of the following:

		2010		2009

Support equipment and lease and well equipment inventory	$	272,000	$	261,000
Plugging bonds		60,000		60,000
Other non-current assets		119,000		137,000

Total support equipment and other non-current assets	$	451,000	$	458,000

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

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

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4. Accrued Liabilities

Accrued liabilities for the years ended March 31, 2010 and 2009 consisted of the following:

		2010		2009

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

Total	$	1,836,000	$	1,328,000

5. Asset Retirement Obligation

We recognize the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated present value of the asset retirement cost is capitalized as part of the carrying amount, and is included in the proved oil and gas properties in the accompanying consolidated balance sheets. We own oil and gas properties that require expenditures to plug and abandon when reserves in the wells are depleted. These future expenditures are recorded in the period the liability is incurred (at the time the wells are drilled and completed or acquired).

The following table summarizes the activity related to our estimate of future asset retirement obligations for the years ended March 31, 2010 and 2009:

		2010		2009

Asset retirement obligation at beginning of period	$	1,698,000	$	2,179,000
Liabilities settled during the period		(134,000)		(168,000)
New obligations for wells drilled and completed		54,000		33,000
Accretion of asset retirement obligation		166,000		98,000
Revisions to estimates		(10,000)		(444,000)

Asset retirement obligation at end of period	$	1,774,000	$	1,698,000

Current liability	$	100,000	$	140,000
Long-term liability		1,674,000		1,558,000

Asset retirement obligation at end of each period	$	1,774,000	$	1,698,000

Asset retirement expense as recorded in the years ended March 31, 2010 and 2009 represents plugging and abandonment costs in excess of the estimated asset retirement obligation recorded. We based our initial estimates on our knowledge and experience plugging wells in earlier years.

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6. Credit Line

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

Under the credit facility, we must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. With the December 31, 2008 amendment, the covenant requiring us to maintain a net worth of at least $1,750,000 was replaced with a covenant requiring us to maintain a debt-to-equity ratio less than one. Another covenant obligates us to maintain a current ratio of at least 1:1 inclusive of unused borrowing capacity and exclusive of the current portion of long-term debt. We were in compliance with all covenants at March 31, 2010.

This credit line is collateralized by a significant portion of our oil and gas properties and production, and as of March 31, 2010, there was no outstanding balance on this line of credit. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities that might arise.

7. Commitments

Effective March 1, 2008, we relocated to a new 4,000 square foot office space located in downtown Denver, Colorado. The lease agreement is for a five-year term through April 2013 and currently requires base rent payments of approximately $5,853 per month escalating at a rate of approximately $170 at the end of each year. Office rent expense was approximately $107,000 in 2010 (including building maintenance charges), and $87,000 in 2009. We are committed to a total of $281,000 for the five-year term ending April 1, 2013. Prior to expiration of the lease term, we will evaluate the Denver real estate market and the various available options before deciding on where to lease office space after April 2013.

8. Shareholders’ Equity

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

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

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A summary of the status of our stock option plan and outstanding options as of March 31, 2010 and 2009, and changes during the years ended on those dates is presented below:

	2010				2009
			Weighted					Weighted
			Average					Average
			Exercise					Exercise
	Shares		Price		Shares			Price

Options unexercised, beginning of year		—	$	—		25,000		$	0.1325

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

Options unexercised and exercisable, end of year		—	$	—		—		$	—

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

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

9. Income Tax

Our provision for income taxes for the years ended March 31, 2010 and 2009 comprised of the following:

	2010			2009
Current:
Federal	$	171,000		$	305,000
State		1,000			41,000
Total current income tax expense		172,000			346,000

Deferred:
Federal		(23,000	)		(483,000	)
State		(1,000	)		(75,000	)
Total deferred income tax expense (benefit)		(24,000	)		(558,000	)

Income tax expense (benefit)	$	148,000		$	(212,000	)

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A reconciliation between the income tax provision at the statutory rate on income taxes and the income tax provision for the years ended March 31, 2010 and 2009 is as follows:

	2010			2009

Federal taxes at statutory rate	$	400,000		$	124,000
State taxes, net of federal benefit		9,000			(18,000	)
Excess percentage depletion		(283,000	)		(322,000	)
Other adjustments		22,000			4,000

Income tax expense (benefit)	$	148,000		$	(212,000	)

The components of the net deferred tax assets and liabilities for the years ended March 31, 2010 and 2009 are as follows:

	2010			2009
Deferred tax assets:
Allowance for doubtful accounts	$	31,000		$	26,000
Asset retirement obligation		647,000			633,000
Statutory depletion carryforward		1,074,000			858,000

Gross deferred tax assets		1,752,000			1,517,000

Other accruals		47,000			(4,000	)
Depreciation, depletion and intangible drilling costs		(4,016,000	)		(3,755,000	)

Gross deferred tax liabilities		(3,969,000	)		(3,759,000	)

Deferred tax assets (liabilities), net	$	(2,217,000	)	$	(2,242,000	)

We follow authoritative guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements. Tax positions must meet a “more-likely-than-not” recognition threshold before a benefit is recognized in the financial statements. As of March 31, 2010, the Company has not recorded a liability for uncertain tax positions. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. No interest and penalties related to uncertain tax positions were accrued at March 31, 2010. The tax years remaining subject to examination by tax authorities are fiscal years 2005 through 2009.

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10. Related Party Transactions

It is our policy that officers or directors may assign to us or receive assignments from us in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. It is also our policy that officers or directors and the Company may participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by non-related third parties. In 2010, Ray Singleton, President of the Company, participated in the drilling of the Crown 41-31 in Sheridan County, Montana on the same terms and conditions as other third parties. The well resulted in a dry hole. During 2010 and 2009, none of our other directors or officer participated with the Company in any of our oil and gas transactions. In prior years, Mr. Singleton has participated with us in the acquisition of producing properties on the same terms and conditions as the Company and other third parties. As such, Mr. Singleton paid for his proportionate share of the acquisition costs at the time of the acquisition. With respect to his working interest in the four producing wells in which he currently has an ownership, at March 31, 2010, the Company had a balance due to Mr. Singleton for approximately $10,000 compared to a payable balance due from him of less than $1,000 at March 31, 2009. This was due to his share of oil and gas revenue exceeding the amount due from him for his share of operating expenses from these wells.

11. Oil and Gas Property

The aggregate amount of capitalized costs related to oil and gas properties and the aggregate amount of related accumulated depreciation and depletion at March 31, 2010 and 2009 are as follows:

		2010		2009

Proved property	$	33,915,000	$	32,187,000
Unproved property		1,555,000		1,077,000

		35,470,000		33,264,000
Accumulated depletion and impairment		(23,582,000)		(22,397,000)

Net capitalized oil and gas property	$	11,888,000	$	10,867,000

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

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

Banks Field. The Banks Field represents approximately 20.5% of total unproved property costs, $318,000, associated with a 13,000 gross acre horizontal Bakken play in McKenzie County, North Dakota.

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

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The following table shows, by category and date incurred, the oil and gas property costs applicable to unproved property that were excluded from the depreciation and depletion computation at March 31, 2010:

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

March 31, 2010	$	1,000	$	791,000	$	—	$	792,000
March 31, 2009		249,000		—		—		249,000
March 31, 2008		29,000		—		—		29,000
March 31, 2007		308,000		—		—		308,000
March 31, 2006		134,000		39,000		—		173,000
March 31, 2005		4,000		—		—		4,000

Total	$	725,000	$	830,000	$	—	$	1,555,000

Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2010 and 2009 are summarized as follows:

		2010		2009

Development costs	$	1,536,000	$	2,177,000
Exploration costs		620,000		—
Acquisitions:
Proved		—		—
Unproved		—		—

Total	$	2,156,000	$	2,177,000

12. Unaudited Oil and Gas Reserves Information

At March 31, 2010 and 2009, 93% and 98% respectively, of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company. The remaining 7% and 2% of the reserve estimates, respectively, were prepared internally by our management. There are many inherent uncertainties in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available, and these changes could be material.

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

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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, 2010				March 31, 2009				March 31, 2008
	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
Proved reserves:
Balance, beginning of year		638,000		936,000		1,074,000		1,120,000		995,000		1,138,000
Revisions of previous estimates (1)		275,000		195,000		(429,000)		(262,000)		112,000		(113,000)
Extensions and discoveries (2)		4,000		10,000		86,000		253,000		19,000		203,000
Sales of reserves in place		—		—		—		—		—		—
Improved recovery		—		—		—		—		15,000		1,000
Purchase of reserves		—		—		—		—		22,000		—
Production (3)		(99,000)		(229,000)		(93,000)		(175,000)		(89,000)		(109,000)

Balance, end of year		818,000		912,000		638,000		936,000		1,074,000		1,120,000

Proved developed reserves:
Balance, beginning of year		587,000		907,000		1,074,000		1,120,000		995,000		1,138,000

Balance, end of year		727,000		912,000		587,000		907,000		1,074,000		1,120,000

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

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

(1)

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

(2)

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

(3)

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

The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to our proved oil and gas reserves. Estimated future cash inflows were computed by applying 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 at March 31, 2010, 2009 and 2008. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

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Standardized Measure of Estimated Discounted Future Net Cash Flows

		For the Years Ended March 31,
		2010		2009		2008

Future cash inflows	$	55,991,000	$	31,793,000	$	114,296,000
Future cash outflows:
Production cost		(29,065,000)		(17,924,000)		(49,599,000)
Development cost		(991,000)		(490,000)		—
Future income taxes		(3,361,000)		(2,100,000)		(17,826,000)

Future net cash flows		22,574,000		11,279,000		46,871,000
Adjustment to discount future annual net cash flows at 10%		(10,060,000)		(4,080,000)		(21,911,000)

Standardized measure of discounted future net cash flows	$	12,514,000	$	7,199,000	$	24,960,000

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

Changes in Standardized Measure of Estimated Discounted Net Cash Flows

		For the Years Ended March, 31
		2010		2009		2008

Standardized measure, beginning of period	$	7,199,000	$	24,960,000	$	14,624,000

Sales of oil and gas, net of production cost		(4,284,000)		(5,808,000)		(4,727,000)
Net change in sales prices, net of production cost		6,279,000		(25,977,000)		14,598,000
Discoveries, extensions and improved recoveries, net of future development cost		154,000		2,298,000		3,054,000
Change in future development costs		467,000		—		—
Development costs incurred during the period that reduced future development cost		—		—		—
Sales of reserves in place		—		—		—
Revisions of quantity estimates		5,280,000		(4,745,000)		2,639,000
Accretion of discount		720,000		4,279,000		1,865,000
Net change in income taxes		(1,582,000)		16,594,000		(4,221,000)
Purchase of reserves		—		—		361,000
Changes in timing of rates of production		(1,719,000)		(4,402,000)		(3,233,000)

Standardized measure, end of period	$	12,514,000	$	7,199,000	$	24,960,000

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ITEM 9

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the phrase “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting 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, 2010. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer. Based on this evaluation, our Chief Executive Officer and Principal Accounting Officer concluded that, as of March 31, 2010, 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.

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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 Principal Accounting 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, 2010.

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

ITEM 9B

OTHER INFORMATION

None.

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Part III

ITEM 10

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ 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 STOCKHOLDER MATTERS

ITEM 13

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

AND DIRECTOR INDEPENDENCE

ITEM 14

PRINCIPAL ACCOUNTANT FEES AND SERVICES

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Part IV

ITEM 15

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

	(1)	Financial Statements
		All financial statements as set forth under Item 8 of this report.

	(2)	Supplementary Financial Statement Schedules
		None.

	(3)	Exhibits
		See (b) below

(b)	Exhibits

	The following exhibits are filed pursuant to Item 601 of Regulation S-K:

Exhibit No.		Document
3(i)a		Restated Certificate of Incorporation of Earthstone Energy, Inc., effective May 12, 1981, as amended by (i) Certificate of Amendment of Certificate of Incorporation, effective November 20, 1986; (ii) Certificate of Amendment of Certificate of Incorporation, effective July 1, 1996; and (iii) Certificate of Designations of Series A Junior Participating Preferred Stock, effective February 5, 2009, incorporated by reference to Exhibit 3(i) of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the SEC on February 17, 2009.
3(i)b		Amended and Restated Certificate of Incorporation as approved by stockholders of the Company at the Company’s 2009 Annual Meeting of Stockholders and the amendments to the Company’s Certificate of Incorporation previously disclosed in 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(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 recent changes made to the Company’s Certificate of Incorporation to remove certain outdated and redundant provisions that existed in our prior bylaws with respect to corporate governance, stockholder and director meeting procedures, and indemnification procedures. Changes to the bylaws include, among other things: (i) amendments to reflect the new name of the Company; (ii) expansion of certain provisions with respect to stockholders’ meetings and record dates; (iii) amendments in respect of corporate governance, board committees, and board meetings; (iv) amendments to certain provisions in respect of officers and their duties; (v) amendments to certain provisions in respect of share certificates; and (vi) removal of indemnification provisions are incorporated by reference to Exhibit 3(ii) on Form 8-K filed with the SEC on March 3, 2010.
4.1		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.
10.1*		Oil and Gas Incentive Compensation Plan, dated April 1, 1980, as amended, incorporated by reference to our Annual Report on Form 10-K for the fiscal year ended March 31, 1985, filed with the SEC.

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(b)

Exhibits (continued)

Exhibit No.		Document
10.2		Loan Agreement, dated March 4, 2002, between The Bank of Cherry Creek and Earthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2002, filed with the SEC on June 28, 2002; as amended by Amended Loan Agreement, dated January 3, 2006, between American National Bank (formerly The Bank of Cherry Creek) and Earthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2006, filed with the SEC on July 14, 2006; and as further amended by Amended Loan Agreement, dated December 31, 2006, between American National Bank and Earthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2009, filed with the SEC on June 29, 2007.
10.3*		Performance Bonus Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.3 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
10.4*		Director Compensation Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.4 of our Amended 10-K/A, filed with the SEC on October 9, 2009 as amended by board resolution dated March 31, 2010, filed herewith.
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 fiscal year ended March 31, 2008, filed with the SEC on July 11, 2008.
10.6*		Part-Time Employment and Confidentiality Agreement, effective March 31,2008, between Joseph Young and Earthstone, incorporated by reference to Exhibit 10.6 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
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 fiscal year ended March 31, 2004, filed with the SEC on May 11, 2005.
16.1		Letter Regarding Change in Certifying Accountant, incorporated herein by reference to Exhibit 16.1 of our Current Report on Form 8-K, filed with the SEC on July 21, 2008.
21		List of Subsidiaries of Earthstone, 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, Chief Executive Officer)
31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer)
32.1		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer)
32.2		Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer).
99.1		Nominating Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.1 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
99.2		Compensation Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.2 of our Amended 10-K/A, filed with the SEC on October 9, 2009.
99.3		Report of Ryder Scott Company filed herewith.

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

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Signatures

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

EARTHSTONE ENERGY, INC.


		Date

By: /s/ Ray Singleton		June 18, 2010

Ray Singleton, President

By: /s/ Joseph Young		June 18, 2010

Joseph Young,
Principal Accounting Officer

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


Name and Capacity		Date

By: /s/ Ray Singleton		June 18, 2010

Ray Singleton, Director

By: /s/ Richard K. Rodgers		June 18, 2010

Richard K. Rodgers, Director and
Compensation Committee Chairman

By: /s/ Monroe W. Robertson		June 18, 2010

Monroe W. Robertson, Director and
Audit Committee Chairman