News Column

EARTHSTONE ENERGY INC - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

June 10, 2014

The following discussion and analysis should be read in conjunction with our financial statements and related notes and the other information appearing in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," and "us" refer to Earthstone Energy, Inc. and its subsidiary collectively. As an oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially and adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is to a large extent determined by factors beyond our control. The discussion set forth describes Earthstone as it is currently configured. If the Exchange agreement is completed, our liquidity outlook, capital structure and planned capital expenditures will be significantly different.



Liquidity and Capital Resources

Liquidity Outlook. Our primary source of funding is the net cash flow from the sale of our oil and natural gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. At the current price of oil, we believe the cash generated from operations, along with existing cash balances and available line of credit, should enable us to meet our existing and normal recurring obligations during the next year and beyond. On December 21, 2012, we entered into a $25 million senior secured revolving bank Credit Facility with the Bank of Oklahoma ("Bank") which provides an additional source of funds to pay our share of drilling and completion costs incurred on wells drilled and completed primarily in the Williston Basin, but also elsewhere. The initial borrowing base on the Credit Facility was $6 million. Among other provisions, the Credit Facility contains certain affirmative and negative covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. For further information concerning the Credit Facility and its terms, see our Form 8-K filed with the SEC on January 3, 2013. Effective September 10, 2013, we entered into a Waiver and First Amendment to Credit Agreement (the "Amended Credit Facility") with the Bank in connection with a semiannual redetermination of the borrowing base. The redetermination resulted in an increase in the borrowing base from $6 million under the initial Credit Facility to $12 million under the Amended Credit Facility, which amount is subject to redetermination. As of March 31, 2014, we had an outstanding balance due of $9 million under the Amended Credit Facility and were in compliance with all covenants contained in the Amended Credit Facility. Our ability to remain in compliance with the financial covenants may be affected by events and other factors beyond our control, including market prices for our oil and gas and the rate at which the operators of projects in which we participate drill. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect our liquidity by rendering us unable to borrow further under the Amended Credit Facility. For further information concerning the Amended Credit Facility and its terms, see the Exhibits below in Part IV - Item 15 of this Form 10-K. Overview of our Capital Structure. We recognize the importance of developing our capital resource base in order to pursue our objectives. However, subsequent to our last public offering in 1980, debt financing has been the sole source of external funding. In addition to our routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, we require capital to fund our exploratory and development drilling efforts and the acquisition of additional properties as well as the enhancement of held and newly acquired properties. 20

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Hedging. During the years ended March 31, 2014 and 2013, we did not participate in any hedging activities, nor did we have any open futures or option contracts.

Working Capital. As of March 31, 2014, we had a working capital surplus of $2,694,000 (a current ratio of 1.47:1) compared to a working capital surplus as of March 31, 2013 of $775,000 (a current ratio of 1.14:1). The increase in current ratio is primarily a result of an increase in oil and gas sales that remained collectible at March 31, 2014 when compared to the prior year, due to an increase in oil and gas sales between the two years. Cash Flow. Cash provided by operating activities increased from $3,867,000 for the year ended March 31, 2013 to $6,441,000 for the year ended March 31, 2014. Changes in operating cash relate primarily to the increase in net income adjusted for non-cash expenses for the year ended March 31, 2014 compared to the comparable prior period. Deferred income tax expense and depletion primarily related to the increase in the oil and gas property balances, coupled with the timing and payment of accounts payable and accrued liabilities, especially pertaining to capital expenditures were also factors in deriving net cash flows from operations. Overall, net cash used in investing activities decreased from the previous year from $12,417,000 for the year ended March 31, 2013 to $10,903,000 for the year ended March 31, 2014. The decrease in cash used relates primarily to decreased expenditures on the acquisition of producing properties, primarily on horizontal Bakken wells in the Williston Basin where for a large portion of the year just one drilling rig was operating in the Banks field as compared to multiple rigs in the prior fiscal period. Net cash provided by financing activities for the years ended March 31, 2014 and 2013 was $4,953,000 and $3,952,000, respectively, related to borrowings on our credit facility, offset by certain fees and costs for that borrowing.



Capital Expenditures

The amounts presented herein are presented on an accrual basis, and as such, may not be consistent with the amounts presented on the consolidated statements of cash flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis. During the year ended March 31, 2014, we incurred capital expenditures of $12,830,000 on various projects. This compares to $13,900,000 for the year ended March 31, 2013. During the year ended March 31, 2014, capital expenditures were comprised of drilling and completions of wells producing as of year-end (54%), drilling of wells to be completed as of calendar year-end (43%), and leaseholds (3%). The majority (88%) of capital expenditures occurred in the Williston Basin. The remainder was spent in other areas on property improvements and leasehold acreage. At present cash flow levels, we expect to have sufficient funds available for our share of both the outstanding AFEs and any additional acreage, seismic and/or drilling cost requirements that might arise from our existing opportunities. We may alter or vary all or part of any planned capital expenditures for reasons including, but not limited to, changes in circumstances, unforeseen opportunities, the inability to negotiate favorable acquisition, farmout, joint venture or divestiture terms, commodity prices, lack of cash flow, and lack of additional funding. We are continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of evaluation. Our policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken. 21 --------------------------------------------------------------------------------



Divestitures/Abandonments

For the year ended March 31, 2014, we divested our interests in a salt water disposal well located in North Dakota for proceeds of $292,000. We plugged and abandoned one well located in Nebraska during the year ended March 31, 2014. The net costs associated with the plugging and abandonment amounted to $56,000.



Impact of Inflation and Pricing

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



Other Commitments

Other than the aforementioned outstanding AFEs, we do not have any other commitments beyond our office lease. See Note 7 to the consolidated financial statements.

22 --------------------------------------------------------------------------------



Results of Operations

Selected Financial Information

The following provides selected financial information and averages for the years ended March 31, 2014 and 2013. Certain prior year amounts may have been reclassified to conform to the current presentation.

Year Ended March 31, 2014 2013 Revenue Oil $ 15,633,000$ 10,283,000 Gas 1 1,807,000 699,000 Total revenue 2 17,440,000 10,982,000 Total production expense 3 3,957,000 3,453,000 Gross profit $ 13,483,000$ 7,529,000 Depletion expense $ 3,768,000$ 1,951,000 Sales volume 4 Oil (Bbls) 173,880 122,655 Gas (Mcfs) 189,933 107,076 BOE 205,536 140,501 Average sales price 5 Oil (per Bbl) $ 89.91$ 83.84 Gas (per Mcf) 6 $ 9.51$ 6.53 BOE $ 84.85$ 78.16 Average per BOE 4, 5, 7 Production expense 5 $ 19.25$ 24.58 Gross profit 5 $ 65.60$ 53.59 Depletion expense 5 $ 18.33$ 13.89 __________________



1 Amount includes NGL revenue. For the years ended March 31, 2014 and 2013,

the NGL revenue included in the gas revenue amount is $808,000 and $221,000,

respectively.

2 Amount does not include water service and disposal revenue. For the years

ended March 31, 2014 and 2013, this revenue amount is net of $74,000 and

$396,000, respectively, in well service and water disposal revenue, which

would otherwise total $17,514,000 and $11,378,000, respectively, in revenue.

3 Overall lifting cost (oil and gas production costs and the cost of

workovers)

4 Estimates of volumes are inherent in reported volumes to coincide with

revenue accruals as a result of the timing of sales information reporting by

third party operators. 5 Averages calculated based upon non-rounded figures.



6 Average gas sales price per Mcf is calculated by dividing total gas and NGL

revenue by the gas sales volume per Mcf. For the years ended March 31, 2014

and 2013, gas sales price per Mcf, exclusive of NGL revenues, was $5.26 per

Mcf and $4.46 per Mcf, respectively.

Per equivalent barrel (6 thousand cubic feet, "Mcf", of gas is equivalent to

7 1 barrel, "Bbl", of oil) 23

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The Year Ended March 31, 2014 Compared with the Year Ended March 31, 2013

Overview. Net income for the year ended March 31, 2014, was $3,939,000 compared to $1,780,000 for the year ended March 31, 2013 a 121% increase. Increases in sales volumes, coupled with increases in the sales price per barrel of oil equivalent ("BOE"), offset by higher production costs and DD&A expense, resulted in the increase in net income. Revenues. Oil and natural gas sales revenue increased $6,458,000 (59%) from $10,982,000 for the year ended March 31, 2013 to $17,440,000 for the year ended March 31, 2014, due to an overall 9% higher realized price per BOE and a 46% overall increase in sales volumes. Volumes and Prices. On an equivalent barrel basis, sales were 206,000 BOE for the year ended March 31, 2014 compared to 141,000 BOE for the year ended March 31, 2013, a 46% increase. Oil sales volumes increased 42% from 122,655 barrels for the year ended March 31, 2013 to 173,880 barrels for the year ended March 31, 2014, while the average price per barrel increased 7% from $83.84 for the year ended March 31, 2013 to $89.91 for the year ended March 31, 2014. The rise in oil volumes resulted from production from newly producing wells offset, partially, by declines in existing wells. Gas sales volumes increased 77% from 107,076 Mcf for the year ended March 31, 2013 to 189,933 Mcf for the year ended March 31, 2014, while the average price per Mcf increased 46%, from $6.53 for the year ended March 31, 2013 to $9.51 for the year ended March 31, 2014. The increase in volumes is primarily related to newly producing wells, coupled with a higher percentage of gas being sold from existing wells as midstream infrastructure is expanded, offset partially by declines in existing wells. Production Expenses. Production expenses are comprised of the following items: Year Ended March 31, 2014 2013 Lease operating expenses $ 2,920,000$ 2,563,000 Workover expenses 689,000 816,000



Transportation and other expenses 348,000 74,000

$ 3,957,000$ 3,453,000 Oil and gas production expense increased $504,000 (15%) for the year ended March 31, 2014, as compared to the year ended March 31, 2013. The two principal components of oil and gas production expense are routine lease operating expenses ("LOE") and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal and minor surface equipment repairs. Workovers primarily include downhole repairs and are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their associated costs can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas production expense from period to period. LOE and transportation and other expenses increased $357,000 (14%) and $274,000 (370%), respectively, for the year ended March 31, 2014, as compared to the year ended March 31, 2013. Workover expense decreased $127,000 (16%) from $816,000 for the year ended March 31, 2013 to $689,000 for the year ended March 31, 2014. 24

-------------------------------------------------------------------------------- The overall lifting cost per BOE decreased $5.33 (22%) from $24.58 for the year ended March 31, 2013 to $19.25 for the year ended March 31, 2014. This decrease resulted from those costs being spread over larger reported BOE volumes. This lifting cost per equivalent barrel is not indicative of all wells, and certain high-cost wells could be shut-in should oil prices drop below certain levels.



Other Expenses.

Depletion and depreciation expense increased $1,864,000 (92%) from $2,017,000 for the year ended March 31, 2013 to $3,881,000 for the year ended March 31, 2014 due to the addition of numerous high-cost North Dakota wells to the depletion base. These newer North Dakota wells reflect a higher investment per well than the remaining, un-expensed depletion base associated with our Legacy properties. Correspondingly, depletion expense per BOE increased from $13.89 for the year ended March 31, 2013 to $18.33 for the year ended March 31, 2014. General and administrative ("G&A") expense increased $3,000 (0.1%) from $2,625,000 for the year ended March 31, 2013, to $2,628,000 for the year ended March 31, 2014. This slight increase in costs is comprised primarily of increases in compensation-related expenses. As a percent of total sales revenue, G&A expense decreased from 23% for the year ended March 31, 2013 to 15% for the year ended March 31, 2014. Income Tax. For the year ended March 31, 2014, we recorded income tax expense of $1,125,000. This amount consisted of a current period benefit of $390,000, resulting from the utilization of previously accumulated net operating losses, and deferred tax expense of $1,515,000. Our effective income tax rate increased from 14.5% for the year ended March 31, 2013 to 22.2% for the year ended March 31, 2014. Our effective income tax rate was higher for the year ended March 31, 2014 primarily due to a decrease in the percentage of current year excess depletion deduction between the comparable periods.



Critical Accounting Policies and Estimates

See Note 1 to the consolidated financial statements.

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires us to disclose both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. We are required to implement this guidance effective for the first quarter of fiscal 2014. The adoption of ASU 2011-11 did not have a material impact on our consolidated financial statements. In July 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists ("ASU 2013-11"). ASU 2013-11 addresses the diversity in practice that exists for the balance sheet presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU No. 2013-11 is effective for our fiscal quarter ending June 30, 2014. ASU 2013-11 impacts balance sheet presentation only. We are currently evaluating the impact of the new rule, but believe the balance sheet impact will not be material.



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

Off Balance Sheet Arrangements

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

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Earthstone Energy, Inc. Table of Contents Consolidated Financial Statements and Accompanying Notes March 31, 2014 and 2013 Page



Re Report of Independent Registered Public Accounting Firm - EKS&H LLLP

27 Consolidated Balance Sheets 28-29 Consolidated Statements of Operations 30 Consolidated Statements of Shareholders' Equity 31 Consolidated Statements of Cash Flows 32 Notes to Consolidated Financial Statements 33-46 26

-------------------------------------------------------------------------------- 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, 2014 and 2013, and the related statements of operations, shareholders' equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Earthstone Energy, Inc. as of March 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. /s/ EKSH LLLP Denver, ColoradoJune 10, 2014 27

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Earthstone Energy, Inc. Consolidated Balance Sheets Page 1 of 2 March 31, March 31, 2014 2013 Assets Current assets: Cash and cash equivalents $ 2,671,000$ 2,180,000 Accounts receivable: Oil and gas sales



3,895,000 2,753,000 Joint interest and other receivables, net of allowance of ($15,000) and ($38,000), respectively

758,000 630,000 Other current assets 1,043,000 814,000 Total current assets 8,367,000 6,377,000 Oil and gas properties, full cost method: Proved properties 67,186,000 53,265,000 Unproved properties 773,000 2,156,000 Accumulated depletion and impairment



(31,496,000 ) (27,729,000 )

Net oil and gas properties



36,463,000 27,692,000

Support equipment and other non-current assets, net of accumulated depreciation of ($514,000) and ($416,000), respectively 791,000 611,000 Total non-current assets 37,254,000 28,303,000 Total assets $ 45,621,000$ 34,680,000

See accompanying notes to consolidated financial statements 28 -------------------------------------------------------------------------------- Earthstone Energy, Inc. Consolidated Balance Sheets Page 2 of 2 March 31, March 31, 2014 2013 Liabilities and Shareholders' Equity Current liabilities: Accounts payable $ 430,000$ 1,631,000 Accrued liabilities 5,243,000 3,971,000 Total current liabilities 5,673,000 5,602,000 Long-term liabilities: Long-term debt 9,000,000 4,000,000 Deferred tax liability 4,486,000 2,971,000 Asset retirement obligation, less current portion 2,068,000 1,809,000 Total long-term liabilities 15,554,000 8,780,000 Total liabilities 21,227,000 14,382,000



Shareholders' equity: Preferred shares, $0.001 par value, 600,000 authorized and none issued or outstanding

- -



Common shares, $0.001 par value, 6,400,000 shares authorized and 1,753,000 and 1,802,000 shares issued, respectively

18,000



18,000

Additional paid-in capital 23,436,000



23,278,000

Treasury stock, at cost, 24,000 and 82,000 shares, respectively

(458,000 ) (457,000 ) Accumulated earnings (deficit) 1,398,000 (2,541,000 ) Total shareholders' equity 24,394,000 20,298,000 Total liabilities and shareholders' equity $ 45,621,000$ 34,680,000 See accompanying notes to consolidated financial statements 29

-------------------------------------------------------------------------------- Earthstone Energy, Inc. Consolidated Statements of Operations Year ended March 31, 2014 2013 Revenues: Oil and gas sales $ 17,440,000$ 10,982,000 Well service and water-disposal revenue 74,000 396,000 Total revenues 17,514,000 11,378,000 Expenses: Oil and gas production 3,957,000 3,453,000 Production tax 1,582,000 971,000 Well service and water-disposal 100,000



94,000

Depletion and depreciation 3,881,000



2,017,000

Accretion of asset retirement obligation 202,000



177,000

General and administrative 2,628,000 2,625,000 Total expenses 12,350,000 9,337,000 Income from operations 5,164,000 2,041,000 Other income (expense): Interest and other income 73,000



62,000

Interest and other expenses (173,000 )



(21,000 )

Total other income (expense) (100,000 ) 41,000 Income before income tax 5,064,000 2,082,000 Current income tax (benefit) expense (390,000 )



62,000

Deferred income tax expense 1,515,000 240,000 Total income tax expense 1,125,000 302,000 Net income $ 3,939,000$ 1,780,000 Per share amounts: Basic $ 2.27$ 1.03 Diluted $ 2.27$ 1.03 Weighted average common shares outstanding: Basic 1,731,812 1,720,712 Diluted 1,731,812 1,720,712

See accompanying notes to consolidated financial statements 30 -------------------------------------------------------------------------------- Earthstone Energy, Inc.



Consolidated Statements of Shareholders' Equity

Years ended March 31, 2014 and 2013 Additional Accumulated Common shares paid-in Treasury shares earnings/ Shares Amount capital Shares Amount (deficit) Total



Balances at March 31, 2012 1,788,000 $ 18,000$ 23,108,000 (82,000 ) $ (457,000 )$ (4,321,000 )$ 18,348,000

Share-based compensation 14,000 - 170,000 - - - 170,000 Net income - - - - - 1,780,000 1,780,000 Balances at March 31, 2013 1,802,000 $ 18,000$ 23,278,000 (82,000 ) $ (457,000 )$ (2,541,000 )$ 20,298,000 Purchase of treasury shares - - - - (1,000 ) - (1,000 ) Share-based compensation 12,000 - 158,000 - - - 158,000 Reclassification of shares held in treasury (58,000 ) - - 58,000 - - - Forfeitures (3,000 ) - - - - - - Net income - - - - - 3,939,000 3,939,000



Balances at March 31, 2014 1,753,000 $ 18,000$ 23,436,000 (24,000 ) $ (458,000 )$ 1,398,000$ 24,394,000

See accompanying notes to consolidated financial statements 31

-------------------------------------------------------------------------------- Earthstone Energy, Inc. Consolidated Statements of Cash Flows Year ended March 31, 2014 2013 Cash flows from operating activities: Net income $ 3,939,000$ 1,780,000 Adjustments to reconcile net income to net cash provided by operating activities: Depletion and depreciation 3,881,000 2,017,000 Deferred income tax expense 1,515,000 240,000 Accretion of asset retirement obligation 202,000 177,000 Share-based compensation 158,000 170,000 Amortization of deferred financing costs 13,000 2,000 Change in: Accounts receivable (1,270,000 ) (904,000 ) Other current assets (501,000 ) (74,000 ) Accounts payable and accrued liabilities



(1,496,000 ) 459,000

Net cash provided by operating activities



6,441,000 3,867,000

Cash flows from investing activities: Oil and gas properties (10,934,000 ) (12,243,000 ) Proceeds from sale of oil and gas property and equipment 292,000 -



Purchases of support equipment and other non-current assets (261,000 ) (174,000 )

Net cash used in investing activities



(10,903,000 ) (12,417,000 )

Cash flows from financing activities: Borrowings on long-term debt 5,000,000 4,000,000 Deferred financing costs (46,000 ) (48,000 ) Purchase of treasury shares (1,000 ) - Net cash provided by financing activities



4,953,000 3,952,000

Cash and cash equivalents: Net increase (decrease) in cash and cash equivalents 491,000 (4,598,000 ) Cash and cash equivalents, beginning of year



2,180,000 6,778,000

Cash and cash equivalents, end of year $



2,671,000 $ 2,180,000

Supplemental disclosure of cash flow information: Cash paid for interest $ 154,000$ 15,000 Cash paid for income tax $ 1,000$ 341,000 Non-cash: Increase in oil and gas property due to asset retirement obligation $ 85,000$ 102,000 Accrued capital expenditures $ 1,539,000$ 1,546,000 Prepaid capital expenditures $ 272,000$ 9,000

See accompanying notes to consolidated financial statements 32 -------------------------------------------------------------------------------- Earthstone Energy, Inc. Notes to Consolidated Financial Statements March 31, 2014



1. Summary of Significant Accounting Policies

Organization and Nature of Operations. Earthstone Energy, Inc. (the "Company") was originally organized in July 1969 as Basic Earth Science Systems, Inc. and changed its name in 2010 to Earthstone Energy, Inc. The Company is principally engaged in the acquisition, exploration, development, and production of crude oil and natural gas properties, primarily operating in the North Dakota and Montana portions of the Williston Basin and South Texas. On May 15, 2014 the Company and Oak Valley, entered into an Exchange Agreement. The Exchange Agreement provides that, upon the terms and subject to the conditions set forth in the Exchange Agreement, Oak Valley will contribute to the Company the membership interests of its three subsidiaries, each a Texas limited liability company, inclusive of producing assets, undeveloped acreage and an estimated $138 million of cash, in exchange for the issuance of approximately 9.1 million shares of the Company's common stock. Following the Exchange, current Earthstone stockholders will own 16% of the Company's outstanding Common Stock and Oak Valley will own 84% of the Company's outstanding Common Stock. The Exchange Agreement has been approved by the board of directors of Earthstone and the board of managers of Oak Valley. See Note 12 below for further information. Principles of Consolidation. The consolidated financial statements include the accounts of Earthstone Energy, Inc. and its wholly-owned subsidiary. All significant intercompany accounts and transactions have been eliminated. The Company does not have any unconsolidated special purpose entities. At the directive of the U.S. Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company uses such terms as "we," "our," "us" or "the Company" in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout the notes to the audited consolidated financial statements, they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board, corporate officers, management, or any individual employee or group of employees.



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

Oil and Gas Sales. The Company derives revenue primarily from the sale of produced natural gas and crude oil. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's interest. Revenues are reported on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between 30 and 90 days after the date of production. Collection of the revenue may vary depending on the status of wells or the performance of the operator. Estimates of the amount of production delivered to purchasers and the prices at which it was delivered are necessary at year end. Management's knowledge of the Company's properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors are the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received, or when better information is available. Oil and Gas Reserves. Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company's control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Oil and Gas Property. The Company uses the full cost method of accounting for costs related to its oil and gas property. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition and exploration activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas property unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves. 33

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



For the years ended March 31, 2014 and 2013, the oil and natural gas prices used to calculate the full cost ceiling limitation are the 12-month average prices, calculated as the unweighted arithmetic average price of oil and gas on the first day of each month for each of the 12 months prior to the last day of the reporting period (unless prices are defined by contractual arrangements) and net cash flows are discounted at ten percent.

Unproved properties are excluded from the ceiling test. Instead, these property costs are periodically reviewed for impairment by reviewing the status of the activity on those properties and surrounding properties either held by the Company or other parties. Capitalized costs of oil and gas properties, excluding those pertaining to unproved properties, are depleted on a composite units-of-production method based on estimated proved reserves. For depletion purposes, the volume of reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Oil and Gas Production Costs. Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Production costs (also referred to as lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities, and severance taxes. Asset Retirement Obligation. The Company's activities are subject to various laws and regulations, including legal and contractual obligation to plug, reclaim, remediate, or otherwise restore oil and gas property at the time such asset ceases to be productive. An asset retirement obligation ("ARO") is initially measured at fair value and recorded as a liability with a corresponding asset when incurred if a reasonable estimate of fair value can be made. This is typically when a well is spud or an asset is placed in service. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the full cost pool. Over time, the liability increases for the change in its present value (and accretion expense is recorded), while the capitalized cost decreases by way of depletion of the full cost pool. Estimates are reviewed quarterly and adjusted in the period in which new information results in a change of estimate. Income Tax. Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. No uncertain tax positions were identified as of any date on or before March 31, 2014. The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of March 31, 2014, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 9 below for further information. Earnings Per Share. Basic and diluted earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Included in our basic and diluted earnings per share calculations are the unvested common shares issued to employees and directors of the Company. Inclusion of the unvested common shares in basic and diluted earnings per share has not resulted in a material variance between basic and diluted earnings per share.



Cash and Cash Equivalents. All highly liquid investments with original maturities of 90 days or less are considered to be cash equivalents. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.

Fair Value Measurements. Financial instruments and nonfinancial assets and liabilities, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board ("FASB"), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The Company's financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, and long-term debt, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments. 34

-------------------------------------------------------------------------------- As discussed in Note 6, the Company incurred asset retirement obligations of $85,000 for the year ended March 31, 2014 and asset retirement obligations of $69,000 and an additional $33,000 related to revisions in estimated liabilities for the year ended March 31, 2013, the value of which was determined using unobservable pricing inputs (or Level 3 inputs). The Company uses the income valuation technique to estimate the fair value of the obligation using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement. Hedging Activities. The Company had no hedging activities in the years ended March 31, 2014 and 2013. 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 the Company is not able to anticipate. Support Equipment. Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years.



Inventory. Inventory, consisting primarily of tubular goods and oil field equipment to be used in future drilling operations or repair operations, is stated at the lower of cost or market, cost being determined by the FIFO method.

Commitments. The Company is committed to $9,880 per month plus maintenance fees on a 7,000 square foot office space located in downtown Denver, Colorado. The lease term ends on April 30, 2016. The Company does not have any off-balance sheet financing transactions, arrangements or obligations. Major Customers and Operating Region. The Company operates exclusively within the United States of America. All of the Company's assets are employed in and all of its revenues are derived from the oil and gas industry. Individual external purchasers of 10% or more of the Company's oil and gas production revenue for the years ended March 31, 2014 and 2013 were as follows: 2014 2013 Valero Energy Corp. 11 % 17 % Plains Marketing LP 6 % 10 % Total 17 % 27 %



For the years ended March 31, 2014 and 2013, approximately 80% and 65%, respectively, of Earthstone's oil and gas revenue was from non-operated properties where the Company has no direct contact with the actual purchaser. On these properties, Earthstone's portion of the product was marketed by the 25 different companies who operate these wells. These 25 companies may, unbeknownst to the Company, market to one or more of the same purchasers to whom the Company sells directly. Therefore, the Company is unable to ascertain the total extent of combined purchaser concentration. It is not expected that the loss of any one of these purchasers would cause a material adverse impact on the Company's results from operations, as alternative markets for oil and gas production are readily available.

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

Share-Based Compensation. The Company recognizes all equity-based compensation as share-based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date. The expense is recognized over the vesting period of the grant. See Note 8 below for information.

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

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

35

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Recent Accounting Pronouncements. In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company was required to implement this guidance effective for the first quarter of fiscal 2014. The adoption of ASU 2011-11 did not have a material impact on its consolidated financial statements.

In July 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists ("ASU 2013-11"). ASU 2013-11 addresses the diversity in practice that exists for the balance sheet presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU No. 2013-11 is effective for the Company's fiscal quarter ending June 30, 2014. ASU 2013-11 impacts balance sheet presentation only. The Company is currently evaluating the impact of the new rule but believes the balance sheet impact will not be material.

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

36

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2. Other Current Assets

Other current assets as of March 31, 2014 and 2013 consisted of:

2014 2013 Prepaid income tax $ 379,000$ 112,000 Lease and well equipment inventory 310,000 371,000 Drilling and completion cost prepayments 223,000 210,000 Prepaid insurance premiums 91,000 88,000 Other current assets 40,000 33,000 Total other current assets $ 1,043,000$ 814,000 Lease and well equipment inventory included in other current assets represents well site production equipment owned by the Company that has been removed from wells that the Company operates. This occurs when the Company plugs a well or replaces 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 the Company from further transferring serviceable equipment to other wells that the Company operates, on an as needed basis. During the year, the Company impaired approximately $61,000 of inventory to production expense. Drilling and completion cost prepayments represent cash expenditures advanced by the Company 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 as of March 31, 2014 and 2013 consisted of:

2014 2013 Support equipment and lease and well equipment inventory $ 590,000$ 500,000 Plugging bonds 122,000 65,000 Deferred financing costs 79,000 46,000 Total other non-current assets $ 791,000 $



611,000

Support equipment represents non-oil and gas property (including such items as vehicles, office furniture and equipment and well servicing equipment) and is stated at the lower of cost or market. Depreciation of support equipment was $114,000 and $66,000 for the years ended March 31, 2014 and 2013, respectively, which was computed using primarily the straight-line method over periods ranging from five to seven years. Non-current lease and well equipment inventory, unlike the equipment inventory in other current assets that is held for resale, is intended for use on leases that the Company operates. This equipment inventory represents well site production equipment that the Company owns that has either been purchased or has been removed from wells that the Company operates. 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 the Company to third parties who supply plugging bonds to federal and state agencies where the Company operates wells. Deferred financing costs represent fees and expenses incurred in connection with the origination of the Company's credit facility in December 2012. These costs will be amortized on a straight-line basis over the five year term of the facility. 37

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4. Accrued Liabilities

Other current liabilities as of March 31, 2014 and 2013 consisted of:

2014 2013 Accrued operations payable $ 4,209,000$ 2,933,000 Accrued compensation 411,000 429,000



Short-term asset retirement obligation 317,000 296,000 Accrued income tax payable and other 180,000 213,000 Revenue and production taxes payable 126,000 100,000

Total accrued liabilities $ 5,243,000$ 3,971,000 5. Long-Term Debt On December 21, 2012 the Company entered into a $25 million senior secured revolving bank credit facility (the "Credit Facility") with the Bank of Oklahoma (the "Bank"). The initial borrowing base on the Credit Facility was $6 million. The maturity date of the Credit Facility is December 21, 2017 and provides for a borrowing base subject to redetermination semi-annually each June and December and for certain unscheduled redeterminations. The Credit Facility is secured by mortgages on primarily all of the Company's properties and an assignment of all the proceeds from severed and extracted hydrocarbons from the properties described in the mortgages. Until further notice, the Bank has suspended their right to receive the proceeds directly. Effective September 10, 2013, the Company entered into a Waiver and First Amendment to Credit Agreement (the "Amended Credit Facility") with the Bank in connection with a semiannual redetermination of the borrowing base. The redetermination resulted in an increase in the borrowing base from $6 million under the initial Credit Facility to $12 million under the Amended Credit Facility, which amount is subject to redetermination. The Company's ability to remain in compliance with the financial covenants may be affected by events and other factors beyond the Company's control, including market prices for the Company's oil and gas and the rate at which the operators of projects drill in which the Company participates. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect the Company's liquidity by rendering the Company unable to borrow further under the Amended Credit Facility. The Credit Facility contains negative covenants that limit the Company's ability, among other things, to pay any cash dividends, incur additional indebtedness, sell assets, enter into hedging contracts, change the nature of its business or operations, merge, consolidate or make investments. In addition, the Company is required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. As of March 31, 2014, the Company was in compliance with all of the financial covenants under the Credit Facility. Should our Exchange Agreement with Oak Valley close we would require the consent of the Bank. Payments of interest are due quarterly in arrears at prime plus 0.75% to 1.75% or LIBOR plus 1.75% to 2.75%, depending on the Company's level of borrowing and election at the date of borrowing. Commitment fees on the unused amounts of the Credit Facility are due quarterly at rates from 0.35% to 0.50% on the unused amounts of the Credit Facility. At closing, the Company paid a borrowing base fee of $30,000, or 0.5%, on the $6 million borrowing base. An additional borrowing base fee of $30,000, or 5%, on the increase in borrowing base of $6 million under the Amended Credit Facility was paid by the Company during the year ended March 31, 2014. These costs have been recorded as deferred financing costs and will be amortized over the term of the facility. Deferred financing fees in the amount of $34,000 related to legal expenses and other costs to originate the Credit Facility and the Amended Credit Facility have been recorded. These costs will be amortized over the term on the facility. Amortization of deferred financing fees in the amount of $13,000 was recorded during the year ended March 31, 2014. Additional borrowing base fees may be payable upon future increases in the borrowing base, if any. As of March 31, 2014, the Company had an outstanding balance under the Credit Facility of $9 million.



6. Asset Retirement Obligation

For the purpose of determining the fair value of the asset retirement obligation incurred during the year ended March 31, 2014, the Company assumed an inflation rate of 4.07%, an estimated average asset life of 30 years, and a credit adjusted risk free interest rate of 7.85%. 38 -------------------------------------------------------------------------------- The following reconciles the value of the asset retirement obligation for the periods presented. This included a short-term obligation of $317,000 and $296,000 as of March 31, 2014 and 2013, respectively, which was a component of accrued liabilities on the balance sheets: 2014 2013 Asset retirement obligation, beginning of year $ 2,105,000$ 1,826,000 Liabilities settled (7,000 ) - Liabilities incurred 85,000 69,000 Revisions in estimated liabilities -



33,000

Accretion 202,000



177,000

Asset retirement obligation, end of year 2,385,000 2,105,000 Less Current portion (317,000 ) (296,000 )



Asset retirement obligation, less current portion $ 2,068,000$ 1,809,000

7. Commitments Office rent expense was approximately $202,000 and $158,000 for the years ended March 31, 2014 and 2013, respectively (including building maintenance charges). The Company is committed to a total of $247,000 for the remaining term on its 7,000 square foot office space located in downtown Denver, Colorado, ending April 30, 2016. 8. Shareholders' Equity Preferred Shares. The Company has 600,000 shares of authorized preferred stock with a par value of $0.001 available for issuance in such series and preferences as determined by the Board. Since inception, the Company has not issued any preferred shares. 39

-------------------------------------------------------------------------------- Common Shares. The Company has authorized 6,400,000 shares of common stock with a par value of $0.001. The total issued common stock as of March 31, 2014, was 1,753,000 common shares. Share-Based Compensation. On March 8, 2007, the Board adopted a Director Compensation Plan ("the Plan") allotting up to 50,728 shares of the Company's common stock to be issued to independent, non-employee directors. In connection with the Plan, an annual stock grant equal to $36,000 is awarded to each independent director. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date. Shares are subject to certain restrictions and vesting. During the year ended March 31, 2014, 6,525 shares of common stock reserved for issuance under the Plan were authorized for issuance. Accordingly, as of March 31, 2014, 3,661 shares of common stock remain available for issuance under the Plan. Grants of shares of restricted stock vest one-third each year over three years. In accordance with the terms of the Plan, if a director's participation as a member of the Board ceases or is terminated for any reason prior to the date the shares of restricted stock are fully vested, the unvested portion of the restricted stock shall be automatically forfeited and shall revert back to the Company. The aggregate number of restricted stock awards outstanding and subject to vesting at March 31, 2014, for each non-employee director was as follows: Robertson - 3,894 shares; Rodgers - 3,894; and Calerich - 3,938. In addition, each of the three independent directors was granted 1,679 shares of restricted stock on April 1, 2014, subject to vesting and forfeiture. All restricted shares are considered issued and outstanding shares of the Company's common stock at the grant date and have the same dividend and voting rights as other common stock. A summary of the status of the Company's non-vested shares under the Director Compensation Plan as of March 31, 2014 and 2013, and changes during the years ended on those dates is presented below: 2014 2013 Weighted Weighted Average Average Grant Grant Date Fair Date Fair Shares Value Shares Value



Non-vested shares, beginning of year 11,755 $ 207,000 14,779

$ 186,000 Granted 6,525 108,000 4,929 108,000 Vested (6,554 ) (99,000 ) (7,953 ) (87,000 ) Forfeited - - - - Non-vested shares, end of year 11,726 $ 216,000 11,755



$ 207,000

As of March 31, 2014, there was $216,000 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Director Compensation Plan. That cost is expected to be recognized over a weighted-average period of 1.70 years.



Share-based compensation expense of $110,000 and $100,000 was recognized during the years ended March 31, 2014 and 2013, respectively, for restricted share grants to independent directors.

The 2011 Equity Incentive Compensation Plan ("the Equity Plan") was adopted by the Board on July 14, 2011, subject to the approval of our Stockholders, which was obtained on September 23, 2011, making the plan effective as of September 23, 2011. The Equity Plan was established to promote our interests and the interests of our Stockholders by encouraging the participants, namely employees, to increase their equity interest in us, thereby giving them an added incentive to work toward the Company's continued growth and success, all the while enabling us to compete for the services of the individuals needed for our continued growth and success. Awards are in the form of restricted shares of common stock. These awards are subject to such restrictions as the Compensation Committee of the Board of Directors may impose, including vesting and risk of forfeiture. The Equity Plan allows up to 150,000 shares of the Company's common stock to be issued to personnel under the plan. During the year ended March 31, 2014, 5,013 shares were granted. Subsequent to the grants, 2,713 shares were forfeited. Subsequent to March 31, 2014, 3,831 shares have been granted. Accordingly, as of June 10, 2014, 135,202 shares of common stock remain available for issuance under the Equity Plan. 40

-------------------------------------------------------------------------------- A summary of the status of the Company's non-vested shares under the Equity Incentive Compensation Plan as of March 31, 2014 and 2013, and changes during the years ended on those dates is presented below: 2014 2013 Weighted Weighted Average Average Grant Grant Date Fair Date Fair Shares Value Shares Value Non-vested shares, beginning of year 7,466 $ 128,000 - $ - Granted 5,013 83,000 9,027 155,000 Vested (2,918 ) (47,000 ) (1,275 ) (21,000 ) Forfeited (2,713 ) (30,000 ) (286 ) (6,000 ) Non-vested shares, end of year 6,848 $ 134,000 7,466 $ 128,000



Share-based compensation expense of $48,000 and $70,000 was recognized during the years ended March 31, 2014 and 2013, respectively, for restricted share grants to employees.

As of March 31, 2014, there was $134,000 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Equity Incentive Compensation Plan. That cost is expected to be recognized over a weighted-average period of 1.78 years. Treasury Shares. On October 22, 2008, the Company's Board authorized a share buyback program for the Company to repurchase up to 5,000 shares of its common stock for a period of up to 18 months. The program did 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 increased the number of shares authorized for repurchase to 15,000 shares. On February 10, 2010, the Board extended the termination date of the program from April 22, 2010 to October 22, 2011. On November 7, 2011, the Board further extended the termination date of the program from October 22, 2011 to October 22, 2013. On November 11, 2013, the Board approved a motion that allowed for up to $5,000 per year to be used to buy back blocks of 99 shares or less. During the year ended March 31, 2014, 30 shares were repurchased at an average price of $17 under the share buyback program and 10,298 shares remain available for future repurchase. No treasury shares have been retired.



9. Income Tax

The provision for income tax for the years ending March 31, 2014 and 2013 is comprised of the following: Year Ended March 31, 2014 2013 Current: Federal $ (387,000 )$ 40,000 State (3,000 ) 22,000



Total current income tax (benefit) expense (390,000 ) 62,000

Deferred:

Federal 1,439,000 226,000 State 76,000 14,000 Total deferred income tax expense 1,515,000 240,000 Income tax expense $ 1,125,000$ 302,000 41

-------------------------------------------------------------------------------- A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the years ended March 31, 2014 and 2013 is as follows: Year Ended March 31, 2014 2013 Federal tax at statutory rate $ 1,722,000$ 708,000 State taxes, net of federal benefit 55,000 18,000 Excess percentage depletion



(678,000 ) (415,000 ) Changes in state rates and other adjustments to deferred taxes

26,000 (9,000 ) Income tax expense $



1,125,000 $ 302,000

Effective rate expressed as a percentage of income before income tax 22.2 % 14.5 % The overall effective tax rate expressed as a percentage of book income before income tax for the year ended March 31, 2014 was 22.2%, as compared to the year ended March 31, 2013 when it was 14.5%, was higher due to a decrease in the percentage of current year excess depletion deduction between the comparable periods.



Income tax payments, net, were $1,000 and $341,000 for the years ended March 31, 2014 and 2013, respectively.

Net deferred tax assets and liabilities were comprised of: Year Ended March 31, 2014 2013 Deferred tax assets:

Statutory depletion carry-forward $ 2,190,000$ 1,467,000 Other accruals 103,000 131,000 Allowance for doubtful accounts 5,000 14,000 Gross deferred tax assets 2,298,000 1,612,000



Deferred tax liabilities:

Depreciation, depletion and intangible drilling costs (6,784,000 ) (4,583,000 )

Gross deferred tax liabilities (6,784,000



) (4,583,000 )

Net deferred tax liabilities $ (4,486,000



) $ (2,971,000 )

Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.

The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are the years ended March 31, 2010 through 2014.

ASC 740 provides detailed 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, 2014, 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 (benefit)/expense. No interest and penalties related to uncertain tax positions were incurred during the years ended March 31, 2014 and 2013.

As of March 31, 2014, the Company has approximately $270,000 of state net operating loss carryovers. Under the various existing state laws, these net operating loss carryovers may be utilized to offset state taxable income through the year ended March 31, 2033.

A portion of the net operating loss carryover begins to expire in 2018.

42 --------------------------------------------------------------------------------



10. Related Party Transactions

The Company maintains a policy permitting officers or directors to assign to the Company or receive assignments from the Company in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. This policy also allows officers or directors and the Company to participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by non-related third parties. During the years ended March 31, 2014 and 2013, no director or officer participated with the Company in any new oil and gas transaction. In prior years, Mr. Singleton has participated with the Company in the acquisition of producing properties on the same terms and conditions as other third parties. As such, Mr. Singleton paid for his proportionate share of the acquisition costs at the time of the acquisition. With respect to his working interest in the three producing wells in which he currently has an ownership, as of March 31, 2014 and 2013, the Company had no accrued balance due to or due from Mr. Singleton.

11. Oil and Gas Properties

The aggregate amount of capitalized costs related to oil and gas property and the aggregate amount of related accumulated depletion and impairment as of March 31, 2014 and 2013 are as follows:

2014 2013 Proved properties $ 67,186,000$ 53,265,000 Unproved properties 773,000 2,156,000



Less accumulated depletion and impairment (31,496,000 ) (27,729,000 )

Total oil and gas properties, net $ 36,463,000$ 27,692,000 The Company divested its interests in a salt water disposal well located in North Dakota for proceeds of $292,000 in the year ended March 31, 2014, which was accounted for as a reduction to proved properties. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas property unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves. The following shows, by category and year incurred, the oil and gas property costs applicable to unproved property that were excluded from the full cost pool depletion computation as of March 31, 2014: Total Exploration Development Acquisition Unproved Costs Incurred During Year Ended Costs Costs Costs Property March 31, 2014 $ - $ - $ 224,000$ 244,000 March 31, 2013 - - 443,000 443,000 Prior Years - - 106,000 106,000 Total $ - $ - $ 773,000$ 773,000



Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2014 and 2013 are summarized as follows:

2014 2013 Development costs $ 12,342,000$ 13,077,000 Exploration costs 488,000 - Acquisitions: Proved - - Unproved - 823,000 Total costs of development, exploration and acquisition activities $ 12,830,000$ 13,900,000 43

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12. Subsequent Events

On May 15, 2014, the Company announced that it had entered into an Exchange Agreement with Oak Valley Resources, LLC ("Oak Valley") whereby the membership interests in three subsidiaries of Oak Valley, inclusive of producing assets, undeveloped acreage and an estimated $138 million of cash, would be contributed and transferred to the Company in exchange for the issuance of approximately 9.1 million shares of the Company's common stock ("Common Stock") to Oak Valley (the "Exchange"). Upon completion of the Exchange, current Company stockholders will own 16% of the Company's outstanding Common Stock and Oak Valley will own 84% of the Company's outstanding Common Stock. Closing conditions include the approval by our shareholders for the issuance to Oak Valley of the Common Stock in the Exchange, approval by our shareholders of an amendment to the certificate of incorporation to increase our authorized capital to 100,000,000 shares of Common Stock and 20,000,000 of Preferred Stock and listing approval by the NYSE MKT of the Common Stock to be issued to Oak Valley in the Exchange. It is anticipated that the Exchange transaction will not be completed until the third calendar quarter of 2014, subject to customary and specific closing conditions. The foregoing summary of the Exchange does not purport to be complete and is qualified in its entirety by statements, documents and other information contained in the Current Report on Form 8-K as filed by the Company with the U.S. Securities Exchange Commission on May 16, 2014.



13. Unaudited Oil and Gas Reserves Information

As of March 31, 2014 and 2013, 100% of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company.

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



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

Proved Reserves March 31, 2014 March 31, 2013 Oil Gas Oil Gas (Bbls) (Mcf) (Bbls) (Mcf) Proved Reserves: Balance, beginning of year 2,457,000 2,786,000 1,227,000 646,000 Revisions of previous estimates1 (88,000 ) 245,000 101,000 148,000 Extensions and discoveries2 359,000 572,000 1,245,000 1,936,000 Sales of reserves in place - - - - Improved recovery - - 7,000 163,000 Purchase of reserves - - - - Production3 (174,000 ) (190,000 )



(123,000 ) (107,000 )

Balance, end of year 2,554,000 3,413,000



2,457,000 2,786,000

Proved developed reserves: Balance, beginning of year 1,388,000 1,182,000



1,077,000 515,000

Balance, end of year 1,526,000 1,773,000



1,388,000 1,182,000

Proved undeveloped reserves: Balance, beginning of year4 1,069,000 1,604,000 150,000 131,000 PUD converted to PDP (405,000 ) (607,000 ) - - PUD added during the year 338,000 633,000 919,000 1,473,000 Revisions of previous estimates 26,000 10,000 - - Balance, end of year 1,028,000 1,640,000 1,069,000 1,604,000 1 Revisions of Previous Estimates - Estimates reflect an overall steady trend of increases in oil and gas prices since December 2008, when prices reached a 5-year low, offset by normal decline curves in wells. 44

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2 Extensions and Discoveries - Additions during the year ended March 31, 2014 consisted of 62 wells, 57 in North Dakota and five in Montana. Extensions and discoveries during the year ended March 31, 2013 consisted of 103 wells, 102 in North Dakota and one in Louisiana. 3 Production - Volumes of oil and gas that were produced were removed from reserves during the year. 4 Proved undeveloped reserves - Positive revisions of 14,000 BOE, or 1%, were made to the March 31, 2013 estimated proved undeveloped reserves balance. The primary cause for these revisions was due to increases in pricing which extended the economic life of the wells. Within portions of the Company's areas of operation, actual well results underperformed relative to the proved undeveloped forecasts in the March 31, 2013 reserve report. The proved undeveloped forecasts in these areas have been adjusted to reflect these well performances in the March 31, 2014 reserve report.



The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company's proved oil and gas reserves. Estimated future cash inflows were computed by applying the 12-month average price of oil and gas on the first day of each month to the estimated future production of proved oil and gas reserves as of March 31, 2014 and 2013. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

Standardized Measure of Estimated Discounted Future Net Cash Flows For the years ended March 31, 2014 2013 Future cash inflows $ 246,908,000$ 217,487,000 Future cash outflows: Production cost (91,392,000 ) (88,280,000 ) Development cost (25,563,000 ) (28,255,000 ) Future income tax



(28,829,000 ) (25,675,000 )

Future net cash flows



101,124,000 75,277,000 Adjustment to discount future annual net cash flows at 10% (52,069,000 ) (43,661,000 )

Standardized measure of discounted future net cash flows $ 49,055,000$ 31,616,000

45 -------------------------------------------------------------------------------- The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for each of the years ended March 31, 2014 and 2013: Changes in Standardized Measure of Estimated Discounted Future Net Cash Flows For the years ended March 31, 2014 2013 Standardized measure, beginning of year $ 31,616,000$ 23,183,000 Sales of oil and gas, net of production cost1 (11,901,000 ) (6,558,000 ) Net change in sales prices, net of production cost



10,126,000 (9,648,000 ) Discoveries, extensions and improved recoveries, net of future development cost

6,021,000 21,075,000 Change in future development costs - -



Development costs incurred during the period that reduced future development cost

9,955,000 (2,757,000 ) Sales of reserves in place - - Revisions of quantity estimates (1,487,000 ) 2,036,000 Accretion of discount 5,729,000 3,780,000 Net change in income tax (941,000 ) 3,320,000 Purchase of reserves - - Changes in timing of rates of production



(63,000 ) (2,815,000 )

Standardized measure, end of year $



49,055,000 $ 31,616,000

1 During the fiscal year ended March 31, 2014, we have revised our disclosure to include $971,000 of production taxes previously excluded from Sales of oil and gas, net of production costs as of March 31, 2014. 46 --------------------------------------------------------------------------------



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the phrase "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2014. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Interim Chief Financial Officer concluded that, as of March 31, 2014, 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 47 -------------------------------------------------------------------------------- (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements. Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Interim Chief Financial Officer, we conducted an evaluation of the effectiveness of the Company's internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework, (1992 Version) 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, 2014. Management's report was not subject to attestation by the Company's independent registered public accounting firm pursuant to rules of the SEC 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. 48

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Part III


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