Earthstone Energy (ESTE) 10-K 10 Jun 14 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Mar. 31, 2014	Jun. 09, 2014	Sep. 30, 2013
Document And Entity Information	'	'	'
Entity Registrant Name	'EARTHSTONE ENERGY INC	'	'
Entity Central Index Key	'0000010254	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Mar-14	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--03-31	'	'
Is Entity a Well-known Seasoned Issuer?	'No	'	'
Is Entity a Voluntary Filer?	'No	'	'
Is Entity's Reporting Status Current?	'Yes	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Public Float	'	'	$21,048,567
Entity Common Stock, Shares Outstanding	'	1,729,123	'
Document Fiscal Period Focus	'FY	'	'
Document Fiscal Year Focus	'2014	'	'

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Mar. 31, 2014	Mar. 31, 2013
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 property, 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
LIABILITIES AND SHAREHOLDERS' EQUITY	'	'
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	0	0
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

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2014	Mar. 31, 2013
Assets:	'	'
Allowance of joint interest and other receivable, net	($15,000)	($38,000)
Accumulated depreciation on support equipment and other non-current assets, net	($514,000)	($416,000)
Shareholders' Equity:	'	'
Preferred stock, par value	$0.00	$0.00
Preferred stock, Authorized	600,000	600,000
Preferred stock, Issued	0	0
Preferred stock, outstanding	0	0
Common stock, par value	$0.00	$0.00
Common stock, Authorized	6,400,000	6,400,000
Common stock, Issued	1,753,000	1,802,000
Treasury stock, shares	24,000	82,000

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Operations (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 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

Consolidated_Statements_of_Sha

Consolidated Statements of Shareholders' Equity (USD $)	Common Shares	Additional Paid-In Capital	Treasury Shares	Accumulated Deficit	Total
Beginning Balance, amount at Mar. 31, 2012	$18,000	$23,108,000	($457,000)	($4,321,000)	$18,348,000
Beginning Balance, shares at Mar. 31, 2012	1,788,000	'	-82,000	'	'
Share-based compensation, shares	14,000	'	'	'	'
Share-based compensation, amount	'	170,000	'	'	170,000
Net income	'	'	'	1,780,000	1,780,000
Ending Balance, amount at Mar. 31, 2013	18,000	23,278,000	-457,000	-2,541,000	20,298,000
Ending Balance, shares at Mar. 31, 2013	1,802,000	'	-82,000	'	'
Purchase of treasury shares, amount	'	'	-1,000	'	-1,000
Share-based compensation, shares	12,000	'	'	'	'
Share-based compensation, amount	'	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
Ending Balance, amount at Mar. 31, 2014	$18,000	$23,436,000	($458,000)	$1,398,000	$24,394,000
Ending Balance, shares at Mar. 31, 2014	1,753,000	'	-24,000	'	'

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 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, net	-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	0
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 fees	-46,000	-48,000
Purchase of treasury shares	-1,000	0
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 period	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

1_Summary_of_Significant_Accou

1. Summary of Significant Accounting Policies	12 Months Ended
	Mar. 31, 2014
Accounting Policies [Abstract]	'
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.
	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.
	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.
	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.

2_Other_Current_Assets

2. Other Current Assets	12 Months Ended
	Mar. 31, 2014
Notes to Financial Statements	'
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_NonCurrent_Assets

3. Other Non-Current Assets	12 Months Ended
	Mar. 31, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]	'
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.

4_Accrued_Liabilities

4. Accrued Liabilities	12 Months Ended
	Mar. 31, 2014
Notes to Financial Statements	'
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

5. Long Term Debt	12 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
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

6. Asset Retirement Obligation	12 Months Ended
	Mar. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
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%.
	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

7. Commitments	12 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
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

8. Shareholders' Equity	12 Months Ended
	Mar. 31, 2014
Equity [Abstract]	'
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.
	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.
	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

9. Income Tax	12 Months Ended
	Mar. 31, 2014
Notes to Financial Statements	'
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
	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.

10_Related_Party_Transactions

10. Related Party Transactions	12 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
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

11. Oil and Gas Properties	12 Months Ended
	Mar. 31, 2014
Notes to Financial Statements	'
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
	31-Mar-14	$	-		$	-		$	224,000	$	244,000
	31-Mar-13		-			-			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

12_Subsequent_Events

12. Subsequent Events	12 Months Ended
	Mar. 31, 2014
Subsequent Events [Abstract]	'
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_Reser

13. Unaudited Oil and Gas Reserves Information	12 Months Ended
	Mar. 31, 2014
Extractive Industries [Abstract]	'
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
			31-Mar-14						31-Mar-13
			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.
		2	Extensions and Discoveries – Additions during the year ended March 31, 2014 consisted of 62 gross wells, 57 in North Dakota and five in Montana.  Extensions and discoveries during the year ended March 31, 2013 consisted of 103 gross 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
	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 cost 1			(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.

1_Summary_of_Significant_Accou1

1. Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Mar. 31, 2014
Accounting Policies [Abstract]	'
Principles of Consolidation	'
	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	'
	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	'
	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. 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	'
	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.
	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	'
	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	'
	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 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	'
	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	'
	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	'
	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.
	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	'
	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.  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.  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	'
	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 CustomersB and Operating Region	'
	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	'
	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	'
	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	'
	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	'
	Reclassifications.  Certain prior year amounts were reclassified to conform to current presentation.  Such reclassifications had no effect on the prior year net income, accumulated deficit, net assets or total shareholders' equity.
Recent Accounting Pronouncements	'
	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.

2_Other_Current_Assets_Tables

2. Other Current Assets (Tables)	12 Months Ended
	Mar. 31, 2014
Other Current Assets Tables	'
Other Current Assets	'
		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

3_Other_NonCurrent_Assets_Tabl

3. Other Non-Current Assets (Tables)	12 Months Ended
	Mar. 31, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]	'
Other current non-current assets	'
		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

4_Accrued_Liabilities_Tables

4. Accrued Liabilities (Tables)	12 Months Ended
	Mar. 31, 2014
Accrued Liabilities Tables	'
Accrued Liabilities	'
		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

6_Asset_Retirement_Obligation_

6. Asset Retirement Obligation (Tables)	12 Months Ended
	Mar. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligation	'
		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

8_Shareholders_Equity_Tables

8. Shareholders' Equity (Tables)	12 Months Ended
	Mar. 31, 2014
Equity [Abstract]	'
Share-Based Compensation	'
	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
	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

9_Income_Tax_Tables

9. Income Tax (Tables)	12 Months Ended
	Mar. 31, 2014
Income Tax Tables	'
Provision for income tax	'
		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
Reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision	'
		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	%
Net deferred tax assets and liabilities	'
	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	)

11_Oil_And_Gas_Properties_Tabl

11. Oil And Gas Properties (Tables)	12 Months Ended
	Mar. 31, 2014
Oil And Gas Properties Tables	'
Capitalized costs related to oil and gas property	'
		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
Oil and gas property costs applicable to unproved property excluded from the full cost pool depletion computation	'
										Total
		Exploration			Development			Acquisition		Unproved
	Costs Incurred During Year Ended	Costs			Costs			Costs		Property
	31-Mar-14	$	-		$	-		$	224,000	$	244,000
	31-Mar-13		-			-			443,000		443,000
	Prior Years		-			-			106,000		106,000
	Total	$	-		$	-		$	773,000	$	773,000
Costs incurred in oil and gas property development	'
		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

13_Unaudited_Oil_and_Gas_Reser1

13. Unaudited Oil and Gas Reserves Information (Tables)	12 Months Ended
	Mar. 31, 2014
Extractive Industries [Abstract]	'
Analysis of Changes in Proved Reserves	'
	Proved Reserves
			31-Mar-14						31-Mar-13
			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
	PUDs converted to PDP			(405,000	)		(607,000	)		-			-
	PUDs 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.
		2	Extensions and Discoveries – Additions during the year ended March 31, 2014 consisted of 62 gross wells, 57 in North Dakota and five in Montana.  Extensions and discoveries during the year ended March 31, 2013 consisted of 103 gross 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.
Standardized Measure of Estimated Discounted Future Net 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
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 cost 1			(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.

1_Summary_of_Significant_Accou2

1. Summary of Significant Accounting Policies (Details)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Major customer percentage	17.00%	27.00%
Valero Energy Corp.	'	'
Major customer percentage	11.00%	17.00%
Plains Marketing LP	'	'
Major customer percentage	6.00%	10.00%

2_Other_Current_Assets_Details

2. Other Current Assets (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013
Other Current Assets Details	'	'
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

3_Other_NonCurrent_Assets_Deta

3. Other Non-Current Assets (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013
Other Non-Current Assets Details	'	'
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

4_Accrued_Liabilities_Details

4. Accrued Liabilities (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013
Accrued Liabilities Details	'	'
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

6_Asset_Retirement_Obligation_1

6. Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Asset Retirement Obligation Details	'	'
Asset retirement obligation, beginning of the year	$2,105,000	$1,826,000
Liabilities settled	-7,000	0
Liabilities incurred	85,000	69,000
Revisions in estimated liabilities	0	33,000
Accretion	202,000	177,000
Asset retirement obligation, end of the 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_Details_Narrativ

7. Commitments (Details Narrative) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Commitments Details Narrative	'	'
Office rent expense	$202,000	$158,000
Rent expense remaining amount committed	$247,000	'

8_Shareholders_Equity_Details

8. Shareholders' Equity (Details) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Director Compensation Plan	'	'
Shares:	'	'
Nonvested shares, beginning of year	11,755	14,779
Nonvested shares, Granted	6,525	4,929
Nonvested shares, Vested	-6,554	-7,953
Nonvested shares, Forfeited	0	0
Nonvested shares, end of year	11,726	11,755
Weighted Average Grant Date Fair Value:	'	'
Weighted Average Grant Date Fair Value, beginning of year	$207,000	$186,000
Weighted Average Grant Date Fair Value, Granted	108,000	108,000
Weighted Average Grant Date Fair Value, Vested	-99,000	-87,000
Weighted Average Grant Date Fair Value, Forfeited	0	0
Weighted Average Grant Date Fair Value, end of year	216,000	207,000
Equity Incentive Compensation Plan	'	'
Shares:	'	'
Nonvested shares, beginning of year	7,466	0
Nonvested shares, Granted	5,013	9,027
Nonvested shares, Vested	-2,918	-1,275
Nonvested shares, Forfeited	-2,713	-286
Nonvested shares, end of year	6,848	7,466
Weighted Average Grant Date Fair Value:	'	'
Weighted Average Grant Date Fair Value, beginning of year	128,000	0
Weighted Average Grant Date Fair Value, Granted	83,000	155,000
Weighted Average Grant Date Fair Value, Vested	-47,000	-21,000
Weighted Average Grant Date Fair Value, Forfeited	-30,000	-6,000
Weighted Average Grant Date Fair Value, end of year	$134,000	$128,000

9_Income_Tax_Details

9. Income Tax (Details) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 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

9_Income_Tax_Details_1

9. Income Tax (Details 1) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Tax Details 1	'	'
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	22.20%	14.50%

9_Income_Tax_Details_2

9. Income Tax (Details 2) (USD $)	Mar. 31, 2014	Mar. 31, 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)

11_Oil_and_Gas_Properties_Deta

11. Oil and Gas Properties (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013
Oil And Gas Properties Details	'	'
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

11_Oil_and_Gas_Properties_Deta1

11. Oil and Gas Properties (Details 1) (USD $)	12 Months Ended
	Mar. 31, 2014
Exploration Costs	$0
Development Costs	0
Acquisition Costs	773,000
Total Unproved Property	773,000
Year 1	'
Exploration Costs	0
Development Costs	0
Acquisition Costs	224,000
Total Unproved Property	224,000
Year 2	'
Exploration Costs	0
Development Costs	0
Acquisition Costs	443,000
Total Unproved Property	443,000
Prior Years	'
Exploration Costs	0
Development Costs	0
Acquisition Costs	106,000
Total Unproved Property	$106,000

11_Oil_and_Gas_Properties_Deta2

11. Oil and Gas Properties (Details 2) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Oil And Gas Properties Details 2	'	'
Development costs	$12,342,000	$13,077,000
Exploration costs	488,000	0
Acquisitions: Proved	0	0
Acquisitions: Unproved	0	823,000
Total costs of development, exploration and acquisition activities	$12,830,000	$13,900,000

13_Unaudited_Oil_and_Gas_Reser2

13. Unaudited Oil and Gas Reserves Information (Details)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
	bbl	bbl
	Mcf	Mcf
Oil (Bbls)	'	'
Proved reserves	'	'
Balance, Beginning of year	2,457,000	1,227,000
Revisions of previous estimates	-88,000	101,000
Extensions and discoveries	359,000	1,245,000
Sales of reserves in place	0	0
Improved recovery	0	7,000
Purchases of reserves	0	0
Production	-174,000	-123,000
Balance, End of year	2,554,000	2,457,000
Proved Developed Reserves	'	'
Proved Developed Reserves, Beginning of year	1,388,000	1,077,000
Proved Developed Reserves, End of year	1,526,000	1,388,000
Proved Undeveloped Reserves	'	'
Proved Undeveloped Reserves, Beginning of year	1,069,000	150,000
PUD converted to PDP	-405,000	0
PUD added during the year	338,000	919,000
Revisions of previous estimates	26,000	0
Proved Undeveloped Reserves, End of year	1,028,000	1,069,000
Gas (Mcf)	'	'
Proved reserves	'	'
Balance, Beginning of year	2,786,000	646,000
Revisions of previous estimates	245,000	148,000
Extensions and discoveries	572,000	1,936,000
Sales of reserves in place	0	0
Improved recovery	0	163,000
Purchases of reserves	0	0
Production	-190,000	-107,000
Balance, End of year	3,413,000	2,786,000
Proved Developed Reserves	'	'
Proved Developed Reserves, Beginning of year	1,182,000	515,000
Proved Developed Reserves, End of year	1,773,000	1,182,000
Proved Undeveloped Reserves	'	'
Proved Undeveloped Reserves, Beginning of year	1,604,000	131,000
PUD converted to PDP	-607,000	0
PUD added during the year	633,000	1,473,000
Revisions of previous estimates	10,000	0
Proved Undeveloped Reserves, End of year	1,640,000	1,604,000

13_Unaudited_Oil_and_Gas_Reser3

13. Unaudited Oil and Gas Reserves Information (Details 1) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Unaudited Oil And Gas Reserves Information Details 1	'	'
Future cash inflows	$246,908,000	$217,487,000
Future production costs	-91,392,000	-88,280,000
Future development costs	-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

13_Unaudited_Oil_and_Gas_Reser4

13. Unaudited Oil and Gas Reserves Information (Details 2) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Unaudited Oil And Gas Reserves Information Details 2	'	'
Standardized Measure, beginning of year	$31,616,000	$23,183,000
Sales of oil and gas, net of production cost	-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	0	0
Development costs incurred during the period that reduced future development cost	9,955,000	-2,757,000
Sales of reserves in place	0	0
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
Purchases of reserves	0	0
Change in timing of rates of production	-63,000	-2,815,000
Standardized Measure, end of year	$49,055,000	$31,616,000